Monday,

April
14,
2003
Part
II
Environmental
Protection
Agency
40
CFR
Part
60
Standards
of
Performance
for
Stationary
Gas
Turbines;
Direct
Final
Rule
and
Proposed
Rule
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Federal
Register
/
Vol.
68,
No.
71
/
Monday,
April
14,
2003
/
Rules
and
Regulations
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
60
[
OAR
 
2002
 
0053,
FRL
 
7476
 
5]

RIN
2060
 
AK35
Standards
of
Performance
for
Stationary
Gas
Turbines
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Direct
final
rule;
amendments.

SUMMARY:
This
action
promulgates
amendments
to
several
sections
of
the
standards
of
performance
for
stationary
gas
turbines.
The
amendments
will
codify
several
alternative
testing
and
monitoring
procedures
that
have
routinely
been
approved
by
EPA.
The
amendments
will
also
reflect
changes
in
nitrogen
oxides
(
NOX)
emission
control
technologies
and
turbine
design
since
the
standards
were
originally
promulgated.
DATES:
The
direct
final
rule
will
be
effective
May
29,
2003,
unless
we
receive
adverse
comments
by
May
14,
2003.
If
such
comments
are
received,
then
EPA
will
publish
a
timely
withdrawal
in
the
Federal
Register
indicating
which
provisions
will
become
effective
and
which
provisions
are
being
withdrawn
due
to
adverse
comment.
Any
distinct
amendment,
paragraph
or
section
of
the
direct
final
rule
for
which
we
do
not
receive
adverse
comment
will
become
effective
on
the
date
set
above,
notwithstanding
any
adverse
comment
on
any
other
distinct
amendment,
paragraph,
or
section
of
the
direct
final
rule.
The
incorporation
by
reference
of
certain
publications
in
the
direct
final
rule
is
approved
by
the
Director
of
the
Office
of
the
Federal
Register
as
of
May
29,
2003.

ADDRESSES:
Comments.
By
U.
S.
Postal
Service,
send
comments
(
in
duplicate,
if
possible)
to:
EPA
Docket
Center
(
6102T),
Attention
Docket
Number
OAR
 
2002
 
0053,
U.
S.
EPA,
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460.
In
person
or
by
courier,
deliver
comments
(
in
duplicate,
if
possible)
to:
Air
and
Radiation
Docket,
Attention
Docket
Number
OAR
 
2002
 
0053,
U.
S.
EPA,
1301
Constitution
Avenue,
NW.,
Room
B
 
108,
Washington,
DC
20460.
We
request
that
a
separate
copy
also
be
sent
to
the
contact
person
listed
below
(
see
FOR
FURTHER
INFORMATION
CONTACT).

FOR
FURTHER
INFORMATION
CONTACT:
Mr.
Jaime
Pagan,
Combustion
Group,
Emission
Standards
Division
(
C439
 
01),
U.
S.
EPA,
Research
Triangle
Park,
North
Carolina
27711;
telephone
number
(
919)
541
 
5340;
facsimile
number
(
919)
541
 
5450;
electronic
mail
address
pagan.
jaime@
epa.
gov.

SUPPLEMENTARY
INFORMATION:
Regulated
Entities.
Entities
potentially
regulated
by
this
action
are
those
that
own
and
operate
stationary
gas
turbines,
and
are
the
same
as
the
existing
rule
in
40
CFR
part
60,
subpart
GG.
Regulated
categories
and
entities
include:

Category
NAICS
SIC
Examples
of
regulated
entities
Any
industry
using
a
stationary
combustion
turbine
as
defined
in
the
direct
final
rule.
2211
486210
211111
211112
221
4911
4922
1311
1321
4931
Electric
services.
Natural
gas
transmission.
Crude
petroleum
and
natural
gas.
Natural
gas
liquids.
Electric
and
other
services,
combined.

This
table
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
for
readers
regarding
entities
likely
to
be
regulated
by
this
action.
To
determine
whether
your
facility
is
regulated
by
this
action,
you
should
examine
the
applicability
criteria
in
§
60.330
of
the
final
rule.
If
you
have
questions
regarding
the
applicability
of
this
action
to
a
particular
entity,
consult
the
contact
person
listed
in
the
preceding
FOR
FURTHER
INFORMATION
CONTACT
section.
Docket.
EPA
has
established
an
official
public
docket
for
this
action
under
Docket
ID
No.
OAR
 
2002
 
0053.
The
official
public
docket
consists
of
the
documents
specifically
referenced
in
this
action,
any
public
comments
received,
and
other
information
related
to
this
action.
Although
a
part
of
the
official
docket,
the
public
docket
does
not
include
Confidential
Business
Information
(
CBI)
or
other
information
whose
disclosure
is
restricted
by
statute.
The
official
public
docket
is
the
collection
of
materials
that
is
available
for
public
viewing
at
the
Air
Docket
in
the
EPA
Docket
Center,
Room
B108,
1301
Constitution
Ave.,
NW.,
Washington,
DC
20460.
The
EPA
Docket
Center
Public
Reading
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
The
telephone
number
for
the
Public
Reading
Room
is
(
202)
566
 
1744.
The
telephone
number
for
the
Air
Docket
is
(
202)
566
 
1742.
Electronic
Access.
You
may
access
this
Federal
Register
document
electronically
through
the
EPA
Internet
under
the
Federal
Register
listings
at
http://
www.
epa.
gov/
fedrgstr/.
An
electronic
version
of
the
public
docket
is
available
through
EPA's
electronic
public
docket
and
comment
system,
EPA
Dockets.
You
may
use
EPA
Dockets
at
http://
www.
epa.
gov/
edocket/
to
view
public
comments,
access
the
index
listing
of
the
contents
of
the
official
public
docket,
and
to
access
those
documents
in
the
public
docket
that
are
available
electronically.
Although
not
all
docket
materials
may
be
available
electronically,
you
may
still
access
any
of
the
publicly
available
docket
materials
through
the
docket
facility
located
above.
Once
in
the
system,
select
search,
then
key
in
the
appropriate
docket
identification
number.
Comments.
We
are
publishing
the
direct
final
rule
without
prior
proposal
because
we
view
this
as
a
noncontroversial
amendment
and
do
not
anticipate
adverse
comments.
However,
in
the
proposed
rules
section
of
this
Federal
Register,
we
are
publishing
a
separate
document
that
will
serve
as
the
proposal
in
the
event
that
adverse
comments
are
filed.
If
we
receive
any
adverse
comments
on
a
specific
element
of
the
direct
final
rule,
we
will
publish
a
timely
withdrawal
in
the
Federal
Register
informing
the
public
which
amendments
will
become
effective
and
which
amendments
are
being
withdrawn
due
to
adverse
comment.
We
will
address
all
public
comments
in
a
subsequent
final
rule
based
on
the
proposed
rule.
Any
of
the
distinct
amendments
in
this
direct
final
rule
for
which
we
do
not
receive
adverse
comment
will
become
effective
on
the
date
set
out
above.
We
will
not
institute
a
second
comment
period
on
the
direct
final
rule.
Any
parties
interested
in
commenting
must
do
so
at
this
time.
World
Wide
Web
(
WWW).
In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
the
direct
final
rule
is
also
available
on
the
WWW
through
the
Technology
Transfer
Network
(
TTN).
Following
signature,
a
copy
of
the
promulgated
direct
final
rule
will
be
posted
on
the
TTN's
policy
and
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Federal
Register
/
Vol.
68,
No.
71
/
Monday,
April
14,
2003
/
Rules
and
Regulations
guidance
page
for
newly
proposed
or
promulgated
rules
at
http://
www.
epa.
gov/
ttn/
oarpg.
The
TTN
provides
information
and
technology
exchange
in
various
areas
of
air
pollution
control.
If
more
information
regarding
the
TTN
is
needed,
call
the
TTN
HELP
line
at
(
919)
541
 
5384.
Outline.
The
information
presented
in
this
preamble
is
organized
as
follows:

I.
Background
II.
Discussion
of
Revisions
A.
Continuous
Monitoring
Options
B.
Optional
Fuel­
Bound
Nitrogen
Allowance
C.
Frequency
of
Fuel
Nitrogen
and
Sulfur
Content
Sampling
D.
Steam
Injection
E.
Test
Methods
for
Sulfur
Content
and
Nitrogen
Content
of
Fuel
F.
Performance
Testing
G.
Measurement
after
Duct
Burner
H.
Option
to
Not
Use
International
Organization
for
Standardization
(
ISO)
Correction
I.
Accuracy
of
Continuous
Monitoring
System
(
CMS)
for
Fuel
Consumption
and
the
Water
or
Steam
to
Fuel
Ratio
J.
Deviations,
Excess
Emissions,
and
Monitor
Downtime
K.
Other
Clarifications
III.
Environmental
and
Economic
Impacts
IV.
Statutory
and
Executive
Order
Reviews
A.
Executive
Order
12866:
Regulatory
Planning
and
Review
B.
Paperwork
Reduction
Act
C.
Regulatory
Flexibility
Act
D.
Unfunded
Mandates
Reform
Act
E.
Executive
Order
13132:
Federalism
F.
Executive
Order
13175:
Consultation
and
Coordination
with
Indian
Tribal
Governments
G.
Executive
Order
13045:
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
H.
Executive
Order
13211:
Actions
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
I.
National
Technology
Transfer
Advancement
Act
J.
Congressional
Review
Act
I.
Background
Under
section
111
of
the
CAA,
42
U.
S.
C.
7411,
the
EPA
promulgated
standards
of
performance
for
stationary
gas
turbines
(
40
CFR
part
60,
subpart
GG).
The
standards
were
originally
promulgated
on
September
10,
1979
(
44
FR
52798).
Since
that
time,
many
changes
in
the
design
of
the
NOX
emission
controls
used
for
and
the
composition
of
the
fuels
fired
in
gas
turbines
have
occurred.
Additional
test
methods
have
also
been
developed
to
measure
emissions
from
gas
turbines
and
the
sulfur
content
of
gaseous
fuels.
As
a
result
of
these
changes,
we
have
had
many
requests
for
case­
by­
case
approvals
of
alternative
testing
and
monitoring
procedures
for
subpart
GG.
We
are
promulgating
the
amendments
to
subpart
GG
to
codify
the
alternatives
that
have
been
routinely
approved.
Additionally,
we
are
attempting
to
harmonize,
where
appropriate,
the
provisions
of
subpart
GG
with
the
monitoring
provisions
of
40
CFR
part
75,
the
continuous
emission
monitoring
requirements
of
the
acid
rain
program
under
title
IV
of
the
CAA,
since
many
existing
and
new
gas
turbines
are
subject
to
both
regulations.

II.
Discussion
of
Revisions
A.
Continuous
Monitoring
Options
Under
the
original
provisions
of
subpart
GG,
any
affected
unit
with
a
water
injection
system
was
required
to
install
and
operate
a
continuous
monitoring
system
to
monitor
and
record
the
fuel
consumption
and
the
ratio
of
water
to
fuel
being
fired
in
the
turbine.
These
operating
parameters
demonstrate
that
a
turbine
continues
to
operate
under
the
same
performance
conditions
as
those
documented
during
the
initial
and
any
subsequent
compliance
tests,
thus
providing
reasonable
assurance
of
compliance
with
the
NOX
standard.
We
are
revising
the
regulation
to
allow
the
use
of
NOX
continuous
emission
monitoring
systems
(
CEMS)
to
demonstrate
compliance,
as
detailed
in
the
following
paragraphs.
Owners
or
operators
of
turbines
that
commenced
construction,
reconstruction,
or
modification
after
October
3,
1977,
but
before
May
29,
2003,
and
that
use
water
or
steam
injection
to
control
NOX
emissions
can
continue
to
use
the
NOX
monitoring
system
which
is
currently
being
used,
or
may
elect
to
use
a
NOX
CEMS.
The
CEMS
must
be
installed,
operated,
and
maintained
according
to
the
appropriate
performance
specification
requirements
in
40
CFR
part
60,
appendix
B.
Alternatively,
sources
may
choose
to
use
data
from
a
NOX
CEMS
that
is
certified
according
to
the
requirements
of
40
CFR
part
75.
Any
owners
or
operators
of
turbines
constructed,
reconstructed,
or
modified
in
this
time
period
that
do
not
use
water
or
steam
injection
and
that
have
received
EPA
approval
of
an
alternative
monitoring
strategy
can
continue
to
follow
the
conditions
of
the
petition
approval.
For
new
turbines
constructed
after
the
effective
date
of
the
direct
final
rule
and
using
water
or
steam
injection
for
NOX
control,
owners/
operators
can
elect
to
use
either
the
existing
requirements
for
continuous
water
or
steam
to
fuel
ratio
monitoring
or
may
elect
to
use
a
CEMS
to
monitor
NOX.
The
CEMS
must
be
installed,
operated,
and
maintained
according
to
Performance
Specifications
(
PS)
2
and
3
of
40
CFR
part
60,
appendix
B.
Alternatively,
sources
may
choose
to
use
data
from
a
NOX
CEMS
that
is
certified
according
to
the
requirements
of
40
CFR
part
75,
appendix
A.
Owners
or
operators
of
new
turbines
that
commence
construction
after
the
effective
date
of
the
direct
final
rule
and
do
not
use
water
or
steam
injection
to
control
NOX
emissions
can
use
a
NOX
CEMS
as
an
alternative
to
continuously
monitoring
fuel
consumption
and
water
or
steam
to
fuel
ratio,
provided
the
CEMS
is
installed,
operated,
and
maintained
according
to
PS
2
and
3
of
40
CFR
part
60,
appendix
B
and
40
CFR
60.13
or
the
requirements
of
40
CFR
part
75,
appendix
A.
An
acceptable
alternative
to
installation
of
a
NOX
CEMS
is
continuous
parameter
monitoring.
If
this
option
is
chosen,
owners
or
operators
of
uncontrolled
diffusion
flame
turbines
must
continuously
monitor
at
least
four
parameters
indicative
of
the
unit's
NOX
formation
characteristics.
For
lean
premix
turbines,
continuous
monitoring
of
parameters
that
indicate
whether
the
turbine
is
operating
in
the
lean
premixed
combustion
mode
is
required.
Examples
of
these
parameters
may
include
percentage
of
full
load,
turbine
exhaust
temperature,
combustion
reference
temperature,
compressor
discharge
pressure,
fuel
and
air
valve
positions,
dynamic
pressure
pulsations,
internal
guide
vane
position,
and
flame
detection
or
flame
scanner
conditions.
Definitions
for
diffusion
flame
turbine
and
lean
premix
turbine
have
been
added
to
the
definitions
section
of
the
final
rule.
Parameters
that
indicate
proper
operation
of
the
emission
control
device
must
be
monitored
for
turbines
that
use
selective
catalytic
reduction.
In
all
cases,
the
acceptable
values
and
ranges
for
the
parameters
must
be
established
during
the
initial
performance
test
for
the
turbine
and
recorded
in
a
parameter
monitoring
plan,
to
be
kept
on­
site.
If
the
option
to
use
a
NOX
CEMS
is
chosen,
we
have
specified
the
minimum
data
requirements.
For
full
operating
hours,
each
monitor
must
complete
at
least
one
cycle
of
operation
(
including
sampling,
analyzing,
and
data
recording)
for
each
15­
minute
quadrant
of
the
hour.
For
partial
unit
operating
hours,
one
valid
data
point
must
be
obtained
for
each
quadrant
of
the
hour
for
which
the
unit
is
operating.
Two
valid
data
points
are
required
for
hours
in
which
required
quality
assurance
and
maintenance
activities
are
performed
on
the
CEMS.
This
data
must
be
reduced
to
hourly
averages
for
purposes
of
identifying
excess
emissions.
The
data
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71
/
Monday,
April
14,
2003
/
Rules
and
Regulations
acquisition
and
handling
system
must
record
the
hourly
NOX
emissions
as
well
as
the
International
Organization
for
Standardization
(
ISO)
standard
conditions
(
if
applicable).
In
lieu
of
recording
the
ISO
standard
conditions,
a
worst
case
ISO
correction
factor
can
be
calculated
using
historical
ambient
data.
For
the
purpose
of
this
calculation,
substitute
the
maximum
humidity
of
ambient
air
(
Ho),
minimum
ambient
temperature
(
Ta),
and
minimum
combustor
inlet
absolute
pressure
(
Po)
into
the
ISO
correction
equation.
By
using
worst
case
parameters
in
this
equation,
the
owner/
operator
can
ensure
compliance
in
all
situations
without
having
to
continuously
monitor
temperature,
humidity
and
pressure.
Several
case­
by­
case
determinations
performed
by
EPA
have
accepted
this
methodology
as
an
alternative
to
continuous
monitoring
of
atmospheric
conditions.
No
data
generated
using
the
data
substitution
methodology
in
40
CFR
part
75
may
be
used.
Instead,
these
periods
of
missing
data
are
identified
and
summarized
in
the
excess
emissions
and
monitoring
report
required
in
40
CFR
60.13.
For
turbines
using
NOX
CEMS,
we
have
defined
excess
emissions
as
any
unit
operating
hour
during
which
the
4­
hour
rolling
average
NOX
concentration
exceeds
the
applicable
emission
limit.
The
averaging
time
selected
for
combustion
turbine
NOX
CEMS
to
define
the
periods
of
excess
emissions
is
a
period
of
4
hours
averaged
each
hour.
The
4­
hour
period
is
representative
of
the
overall
elapsed
time
in
a
typical
EPA
Method
20
of
40
CFR
part
60,
appendix
A,
source
test.
This
period
has
been
found
adequate
to
represent
the
performance
of
combustion
turbine
NOX
emissions
and
NOX
emission
control
systems.
The
4­
hour
period
is
a
relatively
short
averaging
time
compared
to
24­
hour
and
monthly
averaging
times
used
for
other
types
of
combustion
devices
to
account
for
the
NOX
emissions
variability,
particularly
in
solid
fuels.
Combustion
turbines
typically
use
natural
gas
or
No.
2
distillate
oil,
which
have
a
relatively
uniform
fuel
nitrogen
content,
therefore,
a
relatively
short
averaging
time
such
as
4
hours
is
appropriate.
An
averaging
time
of
1
hour
was
also
considered
but
was
rejected
since
4
hours
more
closely
represent
the
typical
duration
of
a
combustion
turbine
stack
test
and
includes
the
ability
to
account
for
a
small
amount
of
nitrogen
variability.
A
1­
hour
period
was
selected
as
the
recurring
(
rolling)
period
for
which
the
4­
hour
averages
are
calculated
since
it
is
already
required
to
be
reported
under
40
CFR
part
75
and
is
convenient
and
appropriate
to
use.
We
are
allowing
the
use
of
NOX
CEMS
as
an
alternative
to
continuously
monitoring
fuel
consumption
and
water
or
steam
to
fuel
ratio
because
the
majority
of
new
turbines
do
not
rely
on
water
injection
for
NOX
control.
Therefore,
for
those
turbines,
the
monitoring
originally
required
by
subpart
GG
is
not
appropriate.
The
use
of
a
NOX
CEMS
will
show
compliance
with
the
NOX
standard
of
subpart
GG
over
all
operating
ranges.
Additionally,
many
of
the
units
affected
by
subpart
GG
are
already
required
to
install
and
certify
CEMS
for
NOX
under
other
requirements,
such
as
the
acid
rain
monitoring
regulation
in
40
CFR
part
75,
or
through
conditions
in
various
permit
requirements.
To
reduce
the
burden
on
these
units,
we
are
allowing
the
use
of
CEMS
units
that
are
certified
according
to
the
requirements
of
40
CFR
part
75.
The
40
CFR
part
75
testing
procedures
to
certify
the
CEMS
are
nearly
identical
to
those
in
40
CFR
part
60,
and
40
CFR
part
75
has
rigorous
quality
assurance
and
quality
control
standards.
We,
therefore,
believe
it
is
appropriate
to
allow
the
use
of
40
CFR
part
75
CEMS
data
for
subpart
GG
compliance
demonstration.
A
definition
of
unit
operating
hour,
which
includes
the
concepts
of
``
full''
and
``
partial''
operating
hours,
is
needed
to
clarify
how
to
validate
an
hour
when
using
CEMS
and
for
the
purpose
of
defining
excess
emissions,
deviations,
and
periods
of
monitor
downtime.

B.
Optional
Fuel­
Bound
Nitrogen
Allowance
The
NOX
emission
standard
in
40
CFR
60.332
includes
a
NOX
emission
allowance
for
fuel­
bound
nitrogen.
The
use
of
this
allowance
for
fuel­
bound
nitrogen
will
be
optional
upon
promulgation
of
the
direct
final
rule.
Owners
or
operators
will
be
able
to
choose
to
accept
a
value
of
zero
for
the
NOX
emission
allowance.
The
NOX
emission
limitations
in
many
State
permits
are
much
more
stringent
than
those
of
subpart
GG.
Many
turbines
are
required
by
their
permits
to
be
fired
only
with
pipeline
quality
natural
gas,
which
is
almost
free
of
fuel­
bound
nitrogen.
Therefore,
these
facilities
are
not
likely
to
use
the
fuel­
bound
nitrogen
credit.

C.
Frequency
of
Fuel
Nitrogen
and
Sulfur
Content
Sampling
Several
revisions
to
the
sampling
frequency
requirements
for
fuel
nitrogen
content
and
fuel
sulfur
content
are
being
made.
1.
Nitrogen
Content
for
Turbines
That
Do
Not
Claim
the
Allowance
for
Fuel
Bound
Nitrogen
We
are
amending
subpart
GG
so
that
sources
are
required
to
monitor
the
nitrogen
content
of
the
fuel
being
fired
in
the
turbine
only
if
they
claim
the
allowance
for
fuel
bound
nitrogen.
For
sources
that
do
not
seek
to
use
the
fuelbound
nitrogen
credit,
the
sampling
requirements
to
determine
the
daily
fuel
nitrogen
concentrations
are
not
required.

2.
Nitrogen
and
Sulfur
Content
for
Turbines
Firing
Fuel
Oil
The
sampling
frequency
for
determining
the
nitrogen
and
sulfur
content
of
fuel
oil
has
been
revised.
Previously
for
bulk
storage
fuels,
sampling
and
analysis
was
required
each
time
new
fuel
was
added.
The
requirement
to
sample
the
nitrogen
and
sulfur
content
of
the
fuel
each
time
fuel
is
transferred
to
the
storage
tank
from
any
other
source
can
be
burdensome
for
a
facility
if
there
are
one
or
more
large
bulk
storage
tanks
which
are
filled
by
tanker
trucks
or
isolated
from
the
turbines
during
the
filling
process.
If
the
fuel
is
not
fed
to
the
turbines
during
the
filling
process,
no
environmental
benefit
is
gained
by
sampling
every
time
oil
is
added
from
a
tanker
truck.
Similarly,
no
environmental
benefit
is
gained
by
sampling
a
tank
which
remains
isolated
from
feeding
turbines
until
it
is
filled.
It
is
less
burdensome
to
allow
a
tank
to
be
filled
completely,
regardless
of
how
many
tanker
trucks
it
takes,
and
then
drawing
a
sample
of
the
combined
fuel.
In
the
end,
this
mixture
of
fuel
is
what
will
be
fed
to
the
turbines.
Thus,
we
are
eliminating
the
requirement
to
sample
each
time
new
fuel
is
added
and
are
allowing
the
use
of
any
of
the
four
sampling
options
from
40
CFR
part
75,
appendix
D.
The
four
options
are
as
follows:
daily
sampling,
flow
proportional
sampling,
sampling
from
a
unit's
storage
tank,
or
sampling
each
delivery.

3.
Sulfur
Content
for
Turbines
Firing
Natural
Gas
A
definition
for
natural
gas
has
been
added
to
the
definitions
section.
It
is
consistent
with
the
latest
definition
in
40
CFR
part
72.
Owners
and
operators
of
turbines
that
are
combusting
natural
gas
are
now
provided
with
alternatives
to
demonstrate
that
the
fuel
meets
the
sulfur
content
requirement.
We
believe
that
sulfur
sampling
is
unnecessary
for
fuels
that
qualify
as
natural
gas.
As
defined
in
the
direct
final
rule,
natural
gas
contains
20.0
grains
or
less
of
total
sulfur
per
100
standard
cubic
feet,

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Rules
and
Regulations
which
equates
to
about
0.06
weight
percent
sulfur
or
600
parts
per
million
by
weight
(
ppmw).
When
natural
gas
is
combusted,
there
is
no
possibility
of
exceeding
the
subpart
GG
sulfur
limit
of
0.8
weight
percent.

4.
Sulfur
and
Nitrogen
Content
for
Turbines
Firing
Gaseous
Fuels
Other
Than
Natural
Gas
Units
that
fire
a
gaseous
fuel
that
is
supplied
without
intermediate
bulk
storage,
but
is
not
natural
gas,
must
determine
and
record
the
sulfur
content
and
(
if
applicable)
nitrogen
content
once
per
day.
Alternatively,
these
units
may
follow
one
of
two
custom
sulfur
sampling
schedules
outlined
in
the
direct
final
rule,
or
they
may
develop
a
custom
schedule
that
is
approved
by
the
Administrator.
One
custom
schedule
requires
daily
sampling
for
30
consecutive
unit
operating
days.
Provided
the
data
indicate
compliance,
the
frequency
can
then
be
reduced
according
to
specific
criteria.
Unit
operating
day
is
now
defined
in
40
CFR
60.331.
Units
may
also
follow
a
custom
schedule
based
on
the
720­
hour
sulfur
sampling
demonstration
described
in
40
CFR
part
75,
appendix
D.
Under
both
schedules,
if
the
margin
of
compliance
is
large,
the
sampling
frequency
can
eventually
be
reduced
to
annually.
We
are
codifying
these
two
custom
schedules
that
have
routinely
been
approved
under
the
subpart
GG
provision
that
allows
sources
to
develop
custom
schedules
for
fuel
sampling
that
must
be
approved
by
the
Administrator.

D.
Steam
Injection
Sources
that
are
using
water
injection
currently
can
monitor
the
ratio
of
water
to
fuel,
as
well
as
fuel
consumption,
to
demonstrate
compliance
with
the
NOX
standard.
We
are
allowing
sources
that
are
using
steam
injection
to
monitor
the
ratio
of
steam
to
fuel
and
fuel
consumption
to
demonstrate
compliance.
Steam
injection
is
another
method
of
NOX
control,
and
water
and
steam
injection
are
the
wet
methods
usually
used.
Steam
injection
monitoring
is
an
acceptable
type
of
parametric
emission
monitoring
method.

E.
Test
Methods
for
Sulfur
Content
and
Nitrogen
Content
of
Fuel
When
subpart
GG
was
originally
promulgated,
no
test
methods
were
specified
for
monitoring
the
nitrogen
content
of
the
fuel.
We
are
specifying
American
Society
of
Testing
and
Materials
(
ASTM)
D2597
 
94(
1999),
ASTM
D6366
 
99,
ASTM
D4629
 
02,
or
ASTM
D5762
 
02
as
acceptable
methods
for
liquid
fuels.
As
the
National
Technology
Transfer
and
Advancement
Act
requires,
we
have
identified
these
voluntary
consensus
standards
and
are
citing
them
for
use.
We
are
not
adding
any
methods
for
determining
the
fuelbound
nitrogen
content
of
the
fuel
being
fired
for
gaseous
fuels
because
none
were
identified.
We
do
not
expect
any
source
owner
to
use
a
gaseous
fuel
with
sufficient
fuel
bound
nitrogen
present
to
claim
a
credit.
Any
source
owner
proposing
credit
for
fuel
bound
nitrogen
in
a
gaseous
fuel
will
have
to
document
an
acceptable
method.
We
have
amended
subpart
GG
to
allow
the
use
of
most
of
the
methods
specified
in
sections
2.2.5
and
2.3.3.1.2
of
40
CFR
part
75,
appendix
D
to
determine
the
total
sulfur
content
of
gaseous
fuel.
The
alternative
methods
for
total
sulfur
provide
more
flexibility
and
harmonize
with
the
requirements
in
40
CFR
part
75.
The
method
ASTM
D3031
 
81
has
been
deleted
from
the
final
rule
because
it
was
discontinued
by
the
ASTM
in
1990
with
no
replacement.
If
the
total
sulfur
content
of
the
fuel
being
fired
in
the
turbine
is
less
than
0.4
weight
percent,
we
are
adding
a
provision
that
the
following
methods
may
be
used
to
measure
the
sulfur
content
of
the
fuel:
ASTM
D4084
 
82
or
94,
D5504
 
01,
D6228
 
98,
or
the
Gas
Processors
Association
Method
2377
 
86.
This
provision
is
consistent
with
the
provision
in
40
CFR
60.13(
j)(
1)
allowing
alternatives
to
reference
method
tests
to
determine
relative
accuracy
of
CEMS
for
sources
with
emission
rates
demonstrated
to
be
less
than
50
percent
of
the
applicable
standard.

F.
Performance
Testing
To
measure
the
NOX
and
diluent
concentration
during
the
performance
test,
we
are
adding
EPA
Method
7E
of
40
CFR
part
60,
appendix
A
used
in
conjunction
with
EPA
Method
3
or
3A
of
40
CFR
part
60,
appendix
A
as
an
acceptable
alternative
to
EPA
Method
20.
In
addition,
we
are
adding
ASTM
D6522
 
00
as
another
alternative
to
EPA
Method
20.
If
ASTM
D6522
 
00
or
EPA
Methods
7E
and
3
or
3A
are
used,
sampling
must
be
conducted
at
a
minimum
of
three
traverse
points,
due
to
concerns
about
potential
stratification
of
pollutant
concentrations
in
the
turbine
stack.
Subpart
GG
previously
required
the
NOX
initial
compliance
testing
to
be
conducted
at
four
different
loads
across
the
unit's
operating
range.
This
testing
was
required
because
of
the
difficulty
in
predicting
which
operating
load
will
represent
worst
case
conditions
when
monitoring
operational
data.
Testing,
therefore,
was
done
across
the
operating
range
to
determine
the
water
to
fuel
ratio
and
fuel
consumption
needed
to
maintain
NOX
compliance
across
the
unit's
normal
operating
range.
One
of
the
tests
was
required
to
be
conducted
at
100
percent
of
peak
load.
We
are
revising
the
final
rule
to
allow
one
test
point
at
90
to
100
percent
of
peak
load.
Due
to
conditions
that
are
beyond
the
control
of
the
turbine
operator,
such
as
ambient
conditions,
it
is
often
not
possible
for
a
turbine
to
be
operated
at
100
percent
of
the
manufacturer's
design
capacity.
Therefore,
the
requirement
to
test
at
100
percent
of
peak
load
has
been
made
more
flexible.
Another
change
is
that
the
initial
performance
test
can
be
performed
at
90
to
100
percent
of
peak
load
only,
instead
of
at
four
different
loads,
if
the
owner
or
operator
chooses
to
use
the
NOX
CEMS
monitoring
option.
The
NOX
CEMS
will
provide
realtime
data
on
NOX
emissions
for
any
given
time
of
operation.
This
data
provides
credible
evidence
which
can
be
used
to
determine
the
unit's
compliance
status
on
a
continuous
basis
following
the
initial
test.
The
availability
of
this
continuous
information
through
the
use
of
NOX
CEMS
after
the
initial
performance
testing
justifies
testing
at
a
single
load
for
the
initial
compliance
testing.
We
are
also
clarifying
how
data
collected
during
a
relative
accuracy
test
audit
(
RATA)
of
the
NOX
CEMS
may
be
used
to
demonstrate
compliance
with
the
performance
tests
required
by
40
CFR
60.8.
The
RATA
consists
of
a
minimum
of
nine
21­
minute
runs
using
EPA
reference
test
methods,
for
a
total
of
189
minutes
or
just
over
3
hours.
This
amount
of
sampling
accompanied
by
sampling
at
multiple
traverse
points
during
a
RATA
provides
enough
representative
emissions
data
to
determine
the
unit's
compliance
status.
Finally,
a
statement
has
been
added
to
clarify
that
if
the
turbine
combusts
both
oil
and
gas,
separate
performance
testing
is
required
for
each
type
of
fuel
combusted
by
the
turbine,
except
for
emergency
fuel.
We
believe
that
this
is
appropriate
due
to
the
fact
that
NOX
emissions
vary
by
fuel
type.

G.
Measurement
After
Duct
Burner
For
sources
that
are
combined
cycle
turbine
systems
using
supplemental
heat,
we
have
added
an
option
that
the
turbine
NOX
emissions
may
be
measured
after
the
duct
burner
rather
than
directly
after
the
turbine.
No
additional
NOX
allowance
is
given.
A
definition
for
duct
burner
has
also
been
added
to
the
definitions
section
of
the
final
rule.
For
combined
cycle
units,
there
are
several
concerns
with
testing
and
monitoring
NOX
at
the
turbine
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Register
/
Vol.
68,
No.
71
/
Monday,
April
14,
2003
/
Rules
and
Regulations
outlet.
For
example,
it
is
questionable
whether
the
turbine
outlet
location
is
suitable
for
installation
of
CEMS.
Moreover,
due
to
the
high
temperature
and
pressure
of
the
turbine
exhaust
at
that
location,
it
may
be
difficult
to
conduct
an
EPA
Method
20
performance
test
at
the
turbine
outlet
of
a
combined
cycle
unit.
In
addition,
any
combined
cycle
units
that
are
subject
to
NOX
CEMS
requirements
for
40
CFR
part
75
or
subparts
Da
and
Db
of
40
CFR
part
60
will
most
likely
have
installed
the
CEMS
after
the
duct
burner,
on
the
heat
recovery
steam
generator
(
HRSG)
stack.
Another
reason
to
allow
measurement
of
NOX
emissions
after
the
duct
burner
is
that
add­
on
NOX
control
systems
such
as
selective
catalytic
reduction
(
SCR)
are
generally
located
after
the
duct
burner;
turbine
NOX
performance
testing
should
be
conducted
after
the
NOX
control
device
and
would,
therefore,
include
emissions
from
the
duct
burner.

H.
Option
To
Not
Use
International
Organization
for
Standardization
(
ISO)
Correction
We
have
added
an
option
to
not
use
the
ISO
correction
equation
for
the
following
units:
lean
premix
combustor
turbines,
units
used
in
association
with
heat
recovery
steam
generators
equipped
with
duct
burners,
and
units
with
add­
on
emission
controls.
This
option
was
added
based
on
discussions
with
the
Gas
Turbine
Association
(
GTA).
The
GTA
indicated
in
letters
to
EPA
on
April
16,
2002,
and
May
30,
2002,
that
the
ISO
correction
equation
was
not
necessary
for
these
units.
These
letters
can
be
found
in
the
docket.

I.
Accuracy
of
Continuous
Monitoring
System
(
CMS)
for
Fuel
Consumption
and
the
Water
or
Steam
to
Fuel
Ratio
The
requirement
that
the
CMS
for
the
fuel
consumption
and
water
or
steam
to
fuel
ratio
for
the
turbine
be
accurate
to
within
5
percent
has
been
removed.
The
numerical
value
of
water
to
fuel
ratio
that
serves
as
a
surrogate
for
the
acceptable
NOX
concentration
is
established
at
each
facility.
This
is
accomplished
by
simultaneously
measuring
the
NOX
concentration
and
using
a
CMS
to
monitor
the
water
or
steam
to
fuel
ratio
that
achieves
that
NOX
level
at
various
turbine
loads
at
the
specific
facility
during
a
performance
test.
This
calibration
serves
to
assure
that
if
the
water
or
steam
to
fuel
ratio
is
maintained
above
this
surrogate
value
using
the
same
CMS,
then
acceptable
NOX
concentration
levels
are
attained
even
if
the
actual
numerical
value
is
not
correct.
Hence,
the
requirement
to
be
accurate
within
plus
or
minus
5
percent
is
not
necessary.
J.
Deviations,
Excess
Emissions,
and
Monitor
Downtime
The
excess
emission
reporting
provisions
under
40
CFR
60.334
have
been
revised
to
include
definitions
of
deviations,
excess
emissions,
and
monitor
downtime
periods
for
the
various
emissions
and
parameter
monitoring
requirements.
To
be
consistent
with
other
40
CFR
part
60
rules,
we
are
including
provisions
for
deviations,
which
are
associated
with
parametric
monitoring.
A
deviation
indicates
the
possibility
that
an
excess
emission
has
occurred.
Periods
of
monitor
downtime
were
not
previously
defined,
so
we
have
added
definitions
for
those
periods.
New
provisions
have
been
added
for
CEMS
and
parametric
monitoring
for
certain
units;
therefore,
it
is
necessary
to
define
the
excess
emissions,
deviations,
and
monitor
downtime
for
turbines
using
these
new
monitoring
options.

K.
Other
Clarifications
Several
other
minor
clarifications
have
been
made
to
the
final
rule.
They
are
as
follows:
(
1)
Indicated
that
the
sulfur
content
standard
in
40
CFR
60.333(
b)
of
0.8
percent
by
weight
is
equivalent
to
8000
ppmw;
(
2)
clarified
the
NOX
standard
in
40
CFR
60.332(
a)(
1)
to
indicate
that
it
is
an
emission
concentration
and
should
be
ISO
corrected
(
if
required);
and
(
3)
clarified
the
NOX
emission
concentration
equation
in
40
CFR
60.335(
b)(
1)
to
indicate
it
is
a
concentration
instead
of
a
rate
and
that
it
is
on
a
dry
basis.

III.
Environmental
and
Economic
Impacts
We
believe
that
the
amendments
will
not
have
any
significant
economic
or
environmental
impacts.
The
changes
have
been
made
primarily
to
codify
routine
testing
and
monitoring
alternatives
that
have
previously
been
approved
by
us.
We
are
not
introducing
any
new
emission
limitations,
control
requirements,
or
monitoring
requirements.
We
are
attempting
to
reduce
the
testing,
monitoring,
and
reporting
burden
by
harmonizing
with
the
requirements
of
40
CFR
part
75,
since
many
gas
turbines
are
subject
to
it
as
well
as
subpart
GG.

IV.
Statutory
and
Executive
Order
Reviews
A.
Executive
Order
12866:
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,
1993),
we
must
determine
whether
a
regulatory
action
is
``
significant''
and,
therefore,
subject
to
review
by
the
Office
of
Management
and
Budget
(
OMB)
and
the
requirements
of
the
Executive
Order.
The
Executive
Order
defines
``
significant
regulatory
action''
as
one
that
is
likely
to
result
in
a
rule
that
may:
(
1)
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more
or
adversely
affect
in
a
material
way
the
economy,
a
sector
of
the
economy,
productivity,
competition,
jobs,
the
environment,
public
health
or
safety,
or
State,
local,
or
tribal
governments
or
communities;
(
2)
Create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;
(
3)
Materially
alter
the
budgetary
impact
of
entitlements,
grants,
user
fees,
or
loan
programs,
or
the
rights
and
obligation
of
recipients
thereof;
or
(
4)
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
Pursuant
to
the
terms
of
Executive
Order
12866,
we
have
determined
that
the
amendments
do
not
constitute
a
``
significant
regulatory
action''
because
they
do
not
meet
any
of
the
above
criteria.
Consequently,
this
action
was
not
submitted
to
OMB
for
review
under
Executive
Order
12866.

B.
Paperwork
Reduction
Act
This
action
does
not
impose
any
new
information
collection
burden.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
The
revisions
contain
no
changes
to
the
information
collection
requirements
of
the
current
New
Source
Performance
Standards
(
NSPS)
that
would
increase
the
burden
to
sources,
and
the
currently
approved
OMB
information
collection
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Federal
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/
Vol.
68,
No.
71
/
Monday,
April
14,
2003
/
Rules
and
Regulations
requests
are
still
in
force
for
the
amended
rule.
Some
changes
in
the
final
rule,
such
as
allowing
the
use
of
CEMS
to
measure
NOX
emissions,
are
provided
as
an
option
to
sources,
and
should
reduce
burden
to
those
sources
who
already
have
a
CEMS
in
place
for
other
regulatory
reasons,
such
as
the
Acid
Rain
requirements
in
40
CFR
part
75.
Other
changes,
such
as
the
allowance
of
parametric
monitoring
in
place
of
water
to
fuel
ratio
monitoring,
do
not
result
in
additional
recordkeeping
and
reporting
requirements
beyond
those
already
required.

C.
Regulatory
Flexibility
Act
The
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601
et
seq.,
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
under
the
Administrative
Procedure
Act
or
any
other
statute,
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
For
purposes
of
assessing
the
impacts
of
the
direct
final
rule
on
small
entities,
small
entity
is
defined
as:
(
1)
A
small
business
whose
parent
company
has
fewer
than
100
or
1,000
employees,
or
fewer
than
4
billion
kW­
hr
per
year
of
electricity
usage,
depending
on
the
size
definition
for
the
affected
North
American
Industry
Classification
System
(
NAICS)
code;
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(
3)
a
small
organization
that
is
any
not­
forprofit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
It
should
be
noted
that
small
entities
in
six
NAICS
codes
may
be
affected
by
the
direct
final
rule,
and
the
small
business
definition
applied
to
each
industry
by
NAICS
code
is
that
listed
in
the
Small
Business
Administration
(
SBA)
size
standards
(
13
CFR
part
121).
After
considering
the
economic
impacts
of
the
direct
final
rule
on
small
entities,
we
certify
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
This
certification
is
based
primarily
upon
the
estimated
cost
savings
to
turbine
owners
and
operators
as
a
result
of
the
revisions
to
40
CFR
part
60,
subpart
GG
that
are
presented
earlier
in
this
preamble.
These
cost
savings
will
be
experienced
by
turbines
owned
and
operated
by
small
entities
as
well
as
large
ones.
Using
the
existing
combustion
turbines
inventory
as
a
measure
of
which
industries
may
install
new
turbines
in
the
future,
presuming
the
existing
mix
of
combustion
turbines
currently
is
a
good
approximation
of
the
mix
of
turbines
that
will
be
installed
and
affected
by
the
direct
final
rule
up
to
2007,
2.5
percent
of
new
turbines
overall
will
likely
be
owned
and
operated
by
small
entities.
Of
these
entities,
a
majority
of
these
are
owned
and
operated
by
small
communities.
For
more
information
on
the
results
of
the
analysis
of
small
entity
impacts,
please
refer
to
the
economic
impact
analysis
in
the
docket.

D.
Unfunded
Mandates
Reform
Act
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Public
Law
104
 
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
EPA
generally
must
prepare
a
written
statement,
including
a
cost­
benefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
by
State,
local,
and
tribal
governments,
in
the
aggregate,
or
by
the
private
sector,
of
$
100
million
or
more
in
any
one
year.
Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
cost
effective,
or
least
burdensome
alternative
that
achieves
the
objective
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
EPA
to
adopt
an
alternative
other
than
the
least
costly,
most
cost
effective,
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
EPA
establishes
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
it
must
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
EPA
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
The
EPA
has
determined
that
the
direct
final
rule
amendments
contain
no
Federal
mandates
that
may
result
in
expenditures
of
$
100
million
or
more
for
State,
local,
and
tribal
governments,
in
the
aggregate,
or
the
private
sector
in
any
one
year.
Thus,
the
amendments
are
not
subject
to
the
requirements
of
sections
202
and
205
of
the
UMRA.
In
addition,
EPA
has
determined
that
the
amendments
contain
no
regulatory
requirements
that
might
significantly
or
uniquely
affect
small
governments
because
they
contain
no
requirements
that
apply
to
such
governments
or
impose
obligations
upon
them.
Therefore,
the
direct
final
rule
amendments
are
not
subject
to
the
requirements
of
section
203
of
the
UMRA.

E.
Executive
Order
13132:
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(
64
FR
43255,
August
10,
1999),
requires
us
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.''
``
Policies
that
have
federalism
implications''
are
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.''
The
direct
final
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
Today's
action
codifies
alternative
testing
and
monitoring
procedures
that
have
routinely
been
approved
by
EPA.
There
are
minimal,
if
any,
impacts
associated
with
this
action.
Thus,
Executive
Order
13132
does
not
apply
to
the
direct
final
rule
amendments.

F.
Executive
Order
13175:
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(
65
FR
67249,
November
6,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.''
``
Policies
that
have
tribal
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/
Rules
and
Regulations
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
one
or
more
Indian
tribes,
on
the
relationship
between
the
Federal
government
and
the
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes.''
The
direct
final
rule
does
not
have
tribal
implications.
It
will
not
have
substantial
direct
effects
on
tribal
governments,
on
the
relationship
between
the
Federal
government
and
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes,
as
specified
in
Executive
Order
13175.
We
do
not
know
of
any
stationary
gas
turbines
owned
or
operated
by
Indian
tribal
governments.
However,
if
there
are
any,
the
effect
of
the
direct
final
rule
on
communities
of
tribal
governments
would
not
be
unique
or
disproportionate
to
the
effect
on
other
communities.
Thus,
Executive
Order
13175
does
not
apply
to
the
direct
final
rule.

G.
Executive
Order
13045:
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045
(
62
FR
19885,
April
23,
1997)
applies
to
any
rule
that:
(
1)
Is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
we
have
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
we
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives.
We
interpret
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
safety
risks,
such
that
the
analysis
required
under
section
5
 
501
of
the
Executive
Order
has
the
potential
to
influence
the
regulation.
The
direct
final
rule
is
not
subject
to
Executive
Order
13045
because
it
is
based
on
technology
performance
and
not
on
health
or
safety
risks.

H.
Executive
Order
13211:
Actions
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
The
direct
final
rule
is
not
subject
to
Executive
Order
13211,
``
Actions
Concerning
Regulations
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use''
because
it
is
not
a
significant
regulatory
action
under
Executive
Order
12866.
I.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
(
NTTAA)
of
1995
(
Public
Law
No.
104
 
113;
15
U.
S.
C.
272
note)
directs
the
EPA
to
use
voluntary
consensus
standards
in
their
regulatory
and
procurement
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(
e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
business
practices)
developed
or
adopted
by
one
or
more
voluntary
consensus
bodies.
The
NTTAA
directs
EPA
to
provide
Congress,
through
annual
reports
to
OMB,
with
explanations
when
an
agency
does
not
use
available
and
applicable
voluntary
consensus
standards.
The
direct
final
rule
involves
technical
standards.
The
EPA
cites
the
following
standards
in
the
direct
final
rule:
EPA
Methods
3,
3A,
7E,
and
20
of
40
CFR
part
60,
appendix
A;
PS
2
and
3
of
40
CFR
part
60,
appendix
B.
In
addition,
the
direct
final
rule
cites
the
following
voluntary
consensus
standards:
ASTM
D129
 
00
(
incorporated
by
reference
(
IBR)
in
40
CFR
part
60,
section
17),
ASTM
D1072
 
80
or
 
90
(
Reapproved
1999)
(
IBR
in
40
CFR
part
60,
section
17),
ASTM
D1266
 
98
(
IBR
in
40
CFR
part
60,
section
17),
ASTM
D1552
 
01
(
IBR
in
40
CFR
part
60,
section
17),
ASTM
D2597
 
94
(
Reapproved
1999),
ASTM
D2622
 
98
(
IBR
in
40
CFR
part
60,
section
17),
ASTM
D3246
 
81
or
 
92
or
 
96
(
IBR
in
40
CFR
part
60,
section
17),
ASTM
D4084
 
82
or
 
94
(
IBR
in
40
CFR
part
60,
section
17),
ASTM
D4294
 
02,
ASTM
D4468
 
85
(
Reapproved
2000),
ASTM
D4629
 
02,
ASTM
D5453
 
00,
ASTM
D5504
 
01,
ASTM
D5762
 
02,
ASTM
D6228
 
98,
ASTM
D6366
 
99,
ASTM
D6522
 
00,
ASTM
D6667
 
01;
and
Gas
Processors
Association
Standard
2377
 
86.
Consistent
with
the
NTTAA,
EPA
conducted
searches
to
identify
voluntary
consensus
standards
in
addition
to
the
EPA
methods.
No
applicable
voluntary
consensus
standards
were
identified
for
EPA
PS
3.
The
search
and
review
results
have
been
documented
and
are
placed
in
the
docket
(
OAR
 
2002
 
0053)
for
the
direct
final
rule.
One
voluntary
consensus
standard
was
found
acceptable
as
an
alternative
to
EPA
test
methods
for
the
purposes
of
the
direct
final
rule.
The
voluntary
consensus
standard
ASTM
D6522
 
00,
``
Standard
Test
Method
for
the
Determination
of
Nitrogen
Oxides,
Carbon
Monoxide,
and
Oxygen
Concentrations
in
Emissions
from
Natural
Gas­
Fired
Reciprocating
Engines,
Combustion
Turbines,
Boilers
and
Process
Heaters
Using
Portable
Analyzers'
was
identified
as
an
acceptable
alternative
to
EPA
Methods
3A,
7E,
and
20
for
identifying
nitrogen
oxide
and
oxygen
concentration
for
the
direct
final
rule
when
the
fuel
is
natural
gas.
In
addition
to
the
voluntary
consensus
standards
EPA
uses
in
the
direct
final
rule,
the
search
for
emissions
measurement
procedures
identified
six
other
voluntary
consensus
standards.
The
EPA
determined
that
these
six
standards
identified
for
measuring
emissions
subject
to
emission
standards
were
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
the
direct
final
rule.
Therefore,
EPA
does
not
intend
to
adopt
these
standards
for
this
purpose.
The
reasons
for
this
determination
for
the
six
methods
are
in
the
docket.
Section
60.335
to
40
CFR
part
60,
subpart
GG,
lists
the
EPA
testing
methods
included
in
the
final
rule.
Under
40
CFR
63.7(
f)
and
63.8(
f),
a
source
may
apply
to
EPA
for
permission
to
use
alternative
test
methods
or
alternative
monitoring
requirements
in
place
of
any
of
the
EPA
testing
methods,
performance
specifications,
or
procedures.

J.
Congressional
Review
Act
The
Congressional
Review
Act,
5
U.
S.
C.
801
et
seq.,
as
added
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996,
generally
provides
that
before
a
rule
may
take
effect,
the
agency
promulgating
the
rule
must
submit
a
rule
report,
which
includes
a
copy
of
the
rule,
to
each
House
of
the
Congress
and
to
the
Comptroller
General
of
the
United
States.
The
EPA
will
submit
a
report
containing
the
direct
final
rule
and
other
required
information
to
the
U.
S.
Senate,
the
U.
S.
House
of
Representatives,
and
the
Comptroller
General
of
the
United
States
prior
to
publication
of
the
direct
final
rule
in
the
Federal
Register.
The
direct
final
rule
is
not
a
``
major
rule''
as
defined
by
5
U.
S.
C.
804(
2).

List
of
Subjects
in
40
CFR
Part
60
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Incorporation
by
reference,
Intergovernmental
relations,
Nitrogen
dioxide,
Reporting
and
recordkeeping
requirements,
Sulfur
oxides.

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Federal
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/
Vol.
68,
No.
71
/
Monday,
April
14,
2003
/
Rules
and
Regulations
Dated:
March
27,
2003.
Christine
Todd
Whitman,
Administrator.


For
the
reasons
stated
in
the
preamble,
title
40,
chapter
I,
part
60,
of
the
Code
of
Federal
Regulations
is
amended
to
read
as
follows:

PART
60
 
[
AMENDED]


1.
The
authority
citation
for
part
60
continues
to
read
as
follows:

Authority:
42
U.
S.
C.
7401,
et
seq.

Subpart
A
 
[
AMENDED]


2.
Section
60.17
is
amended
by:


a.
Removing
and
reserving
paragraph
(
a)(
38);


b.
Revising
paragraph
(
a)
introductory
text;


c.
Revising
paragraph
(
a)(
8);


d.
Revising
paragraph
(
a)(
15);


e.
Revising
paragraph
(
a)(
18);


f.
Revising
paragraph
(
a)(
20);


g.
Revising
paragraph
(
a)(
33);


h.
Revising
paragraph
(
a)(
43);


i.
Revising
paragraph
(
a)(
50);


j.
Adding
paragraphs
(
a)(
65)
through
(
a)(
75);
and

k.
Adding
paragraph
(
m).
The
revisions
and
additions
read
as
follows:

§
60.17
Incorporation
by
Reference.

*
*
*
*
*
(
a)
The
following
materials
are
available
for
purchase
from
at
least
one
of
the
following
addresses:
American
Society
for
Testing
and
Materials
(
ASTM),
100
Barr
Harbor
Drive,
Post
Office
Box
C700,
West
Conshohocken,
PA
19428
 
2959;
or
ProQuest,
300
North
Zeeb
Road,
Ann
Arbor,
MI
48106.
*
*
*
*
*
(
8)
ASTM
D129
 
64,
78,
95,
00,
Standard
Test
Method
for
Sulfur
in
Petroleum
Products
(
General
Bomb
Method),
IBR
approved
for
Appendix
A:
Method
19,
12.5.2.2.3;
§
§
60.106(
j)(
2)
and
60.335(
b)(
10)(
i).
*
*
*
*
*
(
15)
ASTM
D1072
 
80,
90
(
Reapproved
1994),
Standard
Test
Method
for
Total
Sulfur
in
Fuel
Gases,
IBR
approved
for
§
60.335(
b)(
10)(
ii).
*
*
*
*
*
(
18)
ASTM
D1266
 
87,
91,
98,
Standard
Test
Method
for
Sulfur
in
Petroleum
Products
(
Lamp
Method),
IBR
approved
for
§
§
60.106(
j)(
2)
and
60.335(
b)(
10)(
i).
*
*
*
*
*
(
20)
ASTM
D1552
 
83,
95,
01,
Standard
Test
Method
for
Sulfur
in
Petroleum
Products
(
High­
Temperature
Method),
IBR
approved
for
Appendix
A:
Method
19,
Section
12.5.2.2.3;
§
§
60.106(
j)(
2)
and
60.335(
b)(
10)(
i).
*
*
*
*
*
(
33)
ASTM
D2622
 
87,
94,
98,
Standard
Test
Method
for
Sulfur
in
Petroleum
Products
by
Wavelength
Dispersive
X­
Ray
Fluorescence
Spectrometry,''
IBR
approved
for
§
§
60.106(
j)(
2)
and
60.335(
b)(
10)(
i).
*
*
*
*
*
(
43)
ASTM
D3246
 
81,
92,
96,
Standard
Test
Method
for
Sulfur
in
Petroleum
Gas
by
Oxidative
Microcoulometry,
IBR
approved
for
§
60.335(
b)(
10)(
ii).
*
*
*
*
*
(
50)
ASTM
D4084
 
82,
94,
Standard
Test
Method
for
Analysis
of
Hydrogen
Sulfide
in
Gaseous
Fuels
(
Lead
Acetate
Reaction
Rate
Method),
IBR
approved
for
§
60.334(
h)(
1).
*
*
*
*
*
(
65)
ASTM
D2597
 
94
(
Reapproved
1999),
Standard
Test
Method
for
Analysis
of
Demethanized
Hydrocarbon
Liquid
Mixtures
Containing
Nitrogen
and
Carbon
Dioxide
by
Gas
Chromatography,
IBR
approved
for
§
60.335(
b)(
9)(
i).
(
66)
ASTM
D4294
 
02,
Standard
Test
Method
for
Sulfur
in
Petroleum
and
Petroleum
Products
by
Energy­
Dispersive
X­
Ray
Fluorescence
Spectrometry,
IBR
approved
for
§
60.335(
b)(
10)(
i).
(
67)
ASTM
D4468
 
85
(
Reapproved
2000),
Standard
Test
Method
for
Total
Sulfur
in
Gaseous
Fuels
by
Hydrogenolysis
and
Rateometric
Colorimetry,
IBR
approved
for
§
60.335(
b)(
10)(
ii).
(
68)
ASTM
D4629
 
02,
Standard
Test
Method
for
Trace
Nitrogen
in
Liquid
Petroleum
Hydrocarbons
by
Syringe/
Inlet
Oxidative
Combustion
and
Chemiluminescence
Detection,
IBR
approved
for
§
60.335(
b)(
9)(
i).
(
69)
ASTM
D5453
 
00,
Standard
Test
Method
for
Determination
of
Total
Sulfur
in
Light
Hydrocarbons,
Motor
Fuels
and
Oils
by
Ultraviolet
Fluorescence,
IBR
approved
for
§
60.335(
b)(
10)(
i).
(
70)
ASTM
D5504
 
01,
Standard
Test
Method
for
Determination
of
Sulfur
Compounds
in
Natural
Gas
and
Gaseous
Fuels
by
Gas
Chromatography
and
Chemiluminescence,
IBR
approved
for
§
60.334(
h)(
1).
(
71)
ASTM
D5762
 
02,
Standard
Test
Method
for
Nitrogen
in
Petroleum
and
Petroleum
Products
by
Boat­
Inlet
Chemiluminescence,
IBR
approved
for
§
60.335(
b)(
9)(
i).
(
72)
ASTM
D6228
 
98,
Standard
Test
Method
for
Determination
of
Sulfur
Compounds
in
Natural
Gas
and
Gaseous
Fuels
by
Gas
Chromatography
and
Flame
Photometric
Detection,
IBR
approved
for
§
60.334(
h)(
1).
(
73)
ASTM
D6366
 
99,
Standard
Test
Method
for
Total
Trace
Nitrogen
and
Its
Derivatives
in
Liquid
Aromatic
Hydrocarbons
by
Oxidative
Combustion
and
Electrochemical
Detection,
IBR
approved
for
§
60.335(
b)(
9)(
i).
(
74)
ASTM
D6522
 
00,
Standard
Test
Method
for
Determination
of
Nitrogen
Oxides,
Carbon
Monoxide,
and
Oxygen
Concentrations
in
Emissions
from
Natural
Gas­
Fired
Reciprocating
Engines,
Combustion
Turbines,
Boilers,
and
Process
Heaters
Using
Portable
Analyzers,
IBR
approved
for
§
60.335(
a).
(
75)
ASTM
D6667
 
01,
Standard
Test
Method
for
Determination
of
Total
Volatile
Sulfur
in
Gaseous
Hydrocarbons
and
Liquefied
Petroleum
Gases
by
Ultraviolet
Fluorescence,
IBR
approved
for
§
60.335(
b)(
10)(
ii).
*
*
*
*
*
(
m)
This
material
is
available
for
purchase
from
at
least
one
of
the
following
addresses:
The
Gas
Processors
Association,
6526
East
60th
Street,
Tulsa,
OK,
74145;
or
Information
Handling
Services,
15
Inverness
Way
East,
P.
O.
Box
1154,
Englewood,
CO
80150
 
1154.
You
may
inspect
a
copy
at
EPA's
Air
and
Radiation
Docket
and
Information
Center,
Room
B108,
1301
Constitution
Ave.,
NW.,
Washington,
DC
20460.
(
1)
Gas
Processors
Association
Method
2377
 
86,
Test
for
Hydrogen
Sulfide
and
Carbon
Dioxide
in
Natural
Gas
Using
Length
of
Stain
Tubes,
IBR
approved
for
§
60.334(
h)(
1).
(
2)
[
Reserved]
*
*
*
*
*

Subpart
GG
 
[
AMENDED]


3.
Section
60.331
is
amended
by
adding
paragraphs
(
s)
through
(
aa)
to
read
as
follows:

§
60.331
Definitions.

*
*
*
*
*
(
s)
Unit
operating
hour
means
a
clock
hour
during
which
any
fuel
is
combusted
in
the
affected
unit.
If
the
unit
combusts
fuel
for
the
entire
clock
hour,
it
is
considered
to
be
a
full
unit
operating
hour.
If
the
unit
combusts
fuel
for
only
part
of
the
clock
hour,
it
is
considered
to
be
a
partial
unit
operating
hour.
(
t)
Deviation
means
a
unit
operating
hour
during
which
the
recorded
value
of
a
particular
monitored
parameter
is
outside
the
acceptable
range
specified
in
the
parameter
monitoring
plan
for
the
affected
unit.
(
u)
Excess
emissions
means
a
specified
averaging
period
over
which
either
(
1)
the
NOX
emissions
are
higher
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Rules
and
Regulations
than
the
applicable
emission
limit
in
§
60.332;
or
(
2)
the
total
sulfur
content
of
the
fuel
being
combusted
in
the
affected
facility
exceeds
the
limit
specified
in
§
60.333.
(
v)
Natural
gas
means
a
naturally
occurring
fluid
mixture
of
hydrocarbons
(
e.
g.,
methane,
ethane,
or
propane)
produced
in
geological
formations
beneath
the
Earth's
surface
that
maintains
a
gaseous
state
at
standard
atmospheric
temperature
and
pressure
under
ordinary
conditions.
Natural
gas
contains
20.0
grains
or
less
of
total
sulfur
per
100
standard
cubic
feet.
Additionally,
natural
gas
must
either
be
composed
of
at
least
70
percent
methane
by
volume
or
have
a
gross
calorific
value
between
950
and
1100
Btu
per
standard
cubic
foot.
Natural
gas
does
not
include
the
following
gaseous
fuels:
Landfill
gas,
digester
gas,
refinery
gas,
sour
gas,
blast
furnace
gas,
coal­
derived
gas,
producer
gas,
coke
oven
gas,
or
any
gaseous
fuel
produced
in
a
process
which
might
result
in
highly
variable
sulfur
content
or
heating
value.
(
w)
Duct
burner
means
a
device
that
combusts
fuel
and
that
is
placed
in
the
exhaust
duct
from
another
source,
such
as
a
stationary
gas
turbine,
internal
combustion
engine,
kiln,
etc.,
to
allow
the
firing
of
additional
fuel
to
heat
the
exhaust
gases
before
the
exhaust
gases
enter
a
heat
recovery
steam
generating
unit.
(
x)
Lean
premix
stationary
combustion
turbine
means
any
stationary
combustion
turbine
where
the
air
and
fuel
are
thoroughly
mixed
to
form
a
lean
mixture
before
delivery
to
the
combustor.
(
y)
Diffusion
flame
stationary
combustion
turbine
means
any
stationary
combustion
turbine
where
fuel
and
air
are
injected
at
the
combustor
and
are
mixed
only
by
diffusion
prior
to
ignition.
(
z)
Unit
operating
day
means
a
24­
hour
period
between
12
midnight
and
the
following
midnight
during
which
any
fuel
is
combusted
at
any
time
in
the
unit.
It
is
not
necessary
for
fuel
to
be
combusted
continuously
for
the
entire
24­
hour
period.


4.
Section
60.332
is
amended
by:


a.
Revising
the
terms
to
the
equations
in
paragraphs
(
a)(
1)
through
(
3);


b.
Redesignating
paragraph
(
a)(
3)
as
(
a)(
4);
and

c.
Adding
a
new
paragraph
(
a)(
3).
The
revisions
and
additions
read
as
follows:

§
60.332
Standard
for
nitrogen
oxides.

(
a)
*
*
*
(
1)
*
*
*

where:
STD
=
allowable
ISO
corrected
(
if
required
as
given
in
60.335(
b)(
1))
NOX
emission
concentration
(
percent
by
volume
at
15
percent
oxygen
and
on
a
dry
basis),
Y
=
manufacturer's
rated
heat
rate
at
manufacturer's
rated
load
(
kilojoules
per
watt
hour)
or,
actual
measured
heat
rate
based
on
lower
heating
value
of
fuel
as
measured
at
actual
peak
load
for
the
facility.
The
value
of
Y
shall
not
exceed
14.4
kilojoules
per
watt
hour,
and
F
=
NOX
emission
allowance
for
fuelbound
nitrogen
as
defined
in
paragraph
(
a)(
4)
of
this
section.
(
2)
*
*
*

where:
STD
=
allowable
ISO
corrected
(
if
required
as
given
in
60.335(
b)(
1))
NOX
emission
concentration
(
percent
by
volume
at
15
percent
oxygen
and
on
a
dry
basis),
Y
=
manufacturer's
rated
heat
rate
at
manufacturer's
rated
load
(
kilojoules
per
watt
hour)
or,
actual
measured
heat
rate
based
on
lower
heating
value
of
fuel
as
measured
at
actual
peak
load
for
the
facility.
The
value
of
Y
shall
not
exceed
14.4
kilojoules
per
watt
hour,
and
F
=
NOX
emission
allowance
for
fuelbound
nitrogen
as
defined
in
paragraph
(
a)(
4)
of
this
section.
(
3)
The
use
of
F
in
§
60.332(
a)(
1)
and
(
2)
is
optional.
That
is,
the
owner
or
operator
may
choose
to
apply
a
NOX
allowance
for
fuel­
bound
nitrogen
and
determine
the
appropriate
F­
value
in
accordance
with
§
60.332(
a)(
4)
or
may
accept
an
F­
value
of
zero.
(
4)
If
the
owner
or
operator
elects
to
apply
a
NOX
emission
allowance
for
fuel­
bound
nitrogen,
F
shall
be
defined
according
to
the
nitrogen
content
of
the
fuel
during
the
most
recent
performance
test
required
under
§
60.8
as
follows:

Fuel­
bound
nitrogen
(
percent
by
weight)
F
(
NOX
percent
by
volume)

N 
0.015
.....................
0
0.015<
N 
0.1
..............
0.04(
N)
0.1<
N 
0.25
................
0.004+
0.0067(
N
 
0.1)
N>
0.25
.......................
0.005
where:
N
=
the
nitrogen
content
of
the
fuel
(
percent
by
weight).

or:
Manufacturers
may
develop
and
submit
to
EPA
custom
fuel­
bound
nitrogen
allowances
for
each
gas
turbine
model
they
manufacture.
These
fuelbound
nitrogen
allowances
shall
be
substantiated
with
data
and
must
be
approved
for
use
by
the
Administrator
before
the
initial
performance
test
required
by
§
60.8.
Notices
of
approval
of
custom
fuel­
bound
nitrogen
allowances
will
be
published
in
the
Federal
Register.
*
*
*
*
*


5.
Section
60.333
is
amended
by
revising
paragraph
(
b)
to
read
as
follows:

§
60.333
Standard
for
sulfur
dioxide.

*
*
*
*
*
(
b)
No
owner
or
operator
subject
to
the
provisions
of
this
subpart
shall
burn
in
any
stationary
gas
turbine
any
fuel
which
contains
total
sulfur
in
excess
of
0.8
percent
by
weight
(
8000
ppmw).


6.
Section
60.334
is
amended
by:


a.
Revising
paragraphs
(
a)
and
(
b);


b.
Redesignating
paragraph
(
c)
as
paragraph
(
j);


c.
Adding
a
new
paragraph
(
c);


d.
Adding
paragraphs
(
d)
through
(
i);


e.
Revising
newly
designated
paragraphs
(
j)
introductory
text,
(
j)(
1)
and
(
j)(
2);
and

f.
Adding
paragraph
(
j)(
5).
The
revisions
and
additions
read
as
follows:

§
60.334
Monitoring
of
operations.

(
a)
Except
as
provided
in
paragraph
(
b)
of
this
section,
the
owner
or
operator
of
any
stationary
gas
turbine
subject
to
the
provisions
of
this
subpart
and
using
water
or
steam
injection
to
control
NOX
emissions
shall
install,
certify
and
operate
a
continuous
monitoring
system
to
monitor
and
record
the
fuel
consumption
and
the
ratio
of
water
or
steam
to
fuel
being
fired
in
the
turbine.
(
b)
The
owner
or
operator
of
any
stationary
gas
turbine
that
commenced
construction,
reconstruction
or
modification
after
October
3,
1977,
but
before
May
29,
2003,
and
which
uses
water
or
steam
injection
to
control
NOX
emissions
may,
as
an
alternative
to
operating
the
continuous
monitoring
system
described
in
paragraph
(
a)
of
this
section,
install,
certify,
maintain,
operate,
and
quality­
assure
a
continuous
emission
monitoring
system
(
CEMS)
consisting
of
NOX
and
O2
monitors.
If
this
option
is
chosen,
the
CEMS
shall
be
installed,
certified,
maintained,
operated
and
quality­
assured
as
follows:
(
1)
Each
CEMS
must
be
installed
and
certified
according
to
PS
2
and
3
(
for
diluent)
of
40
CFR
part
60,
appendix
B
or
in
accordance
with
the
requirements
of
appendix
A
to
part
75
of
this
chapter.
The
relative
accuracy
test
audit
(
RATA)
of
the
NOX
and
O2
monitors
may
be
performed
individually
or
on
a
combined
basis,
i.
e.,
the
relative
accuracy
tests
of
the
CEMS
may
be
performed
either:
(
i)
On
a
ppm
basis
(
for
NOX)
and
a
percent
O2
basis
for
oxygen;
or
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71
/
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14,
2003
/
Rules
and
Regulations
(
ii)
On
a
ppm
at
15
percent
O2
basis.
(
2)
As
specified
in
§
60.13(
e)(
2),
during
each
full
unit
operating
hour,
each
monitor
must
complete
a
minimum
of
one
cycle
of
operation
(
sampling,
analyzing,
and
data
recording)
for
each
15­
minute
quadrant
of
the
hour,
to
validate
the
hour.
For
partial
unit
operating
hours,
at
least
one
valid
data
point
must
be
obtained
for
each
quadrant
of
the
hour
in
which
the
unit
operates.
For
unit
operating
hours
in
which
required
quality
assurance
and
maintenance
activities
are
performed
on
the
CEMS,
a
minimum
of
two
valid
data
points
(
one
in
each
of
two
quadrants)
are
required
to
validate
the
hour.
(
3)
For
purposes
of
identifying
excess
emissions,
CEMS
data
must
be
reduced
to
hourly
averages
as
specified
in
§
60.13(
h).
(
i)
For
each
unit
operating
hour
in
which
a
valid
hourly
average,
as
described
in
paragraph
(
b)(
2)
of
this
section,
is
obtained
for
both
NOX
and
O2,
the
data
acquisition
and
handling
system
must
calculate
and
record
the
hourly
NOX
emissions
in
the
units
of
the
applicable
NOX
emission
standard
under
§
60.332(
a),
i.
e.,
percent
NOX
by
volume,
dry
basis,
corrected
to
15
percent
O2
and
International
Organization
for
Standardization
(
ISO)
standard
conditions
(
if
required
as
given
in
§
60.335(
b)(
1)).
(
ii)
A
worst
case
ISO
correction
factor
may
be
calculated
and
applied
using
historical
ambient
data.
For
the
purpose
of
this
calculation,
substitute
the
maximum
humidity
of
ambient
air
(
Ho),
minimum
ambient
temperature
(
Ta),
and
minimum
combustor
inlet
absolute
pressure
(
Po)
into
the
ISO
correction
equation.
(
iii)
The
missing
data
substitution
methodology
provided
for
at
40
CFR
Part
75,
subpart
D
may
not
be
used
for
purposes
of
identifying
excess
emissions.
Instead
periods
of
missing
CEMS
data
are
to
be
reported
as
monitor
downtime
in
the
excess
emissions
and
monitoring
performance
report
required
in
§
60.7(
c).
(
4)
Data
from
the
CEMS
shall
be
quality­
assured,
either
in
accordance
with
§
60.13,
or
in
accordance
with
appendix
B
to
part
75
of
this
chapter
(
or,
if
applicable,
§
75.74(
c)(
2)
and
(
3)
of
this
chapter).
(
c)
For
any
new
turbine
that
commenced
construction,
reconstruction
or
modification
after
October
3,
1977,
but
before
May
29,
2003,
and
which
does
not
use
steam
or
water
injection
to
control
NOX
emissions,
the
owner
or
operator
may,
for
purposes
of
determining
excess
emissions,
use
a
CEMS
that
meets
the
requirements
of
paragraph
(
b)
of
this
section.
Also,
if
the
owner
or
operator
has
previously
submitted
and
received
EPA
approval
of
a
petition
for
an
alternative
procedure
of
continuously
monitoring
compliance
with
the
applicable
NOX
emission
limit
under
§
60.332,
that
approved
procedure
may
continue
to
be
used,
even
if
it
deviates
from
paragraph
(
a)
of
this
section.
(
d)
The
owner
or
operator
of
any
new
turbine
constructed
after
May
29,
2003,
and
which
uses
water
or
steam
injection
to
control
NOX
emissions
may
elect
to
use
either
the
requirements
in
paragraph
(
a)
of
this
section
for
continuous
water
or
steam
to
fuel
ratio
monitoring
or
may
use
a
NOX
CEMS
installed,
certified,
operated,
maintained,
and
qualityassured
as
described
in
paragraph
(
b)
of
this
section.
(
e)
The
owner
or
operator
of
any
new
turbine
that
commences
construction
after
May
29,
2003,
and
which
does
not
use
water
or
steam
injection
to
control
NOX
emissions
may
elect
to
use
a
NOX
CEMS
installed,
certified,
operated,
maintained,
and
quality­
assured
as
described
in
paragraph
(
b)
of
this
section.
An
acceptable
alternative
to
installing
a
CEMS
is
described
in
paragraph
(
f)
of
this
section.
(
f)
The
owner
or
operator
of
a
new
turbine
who
elects
not
to
install
a
CEMS
under
paragraph
(
e)
of
this
section,
may
instead
perform
continuous
parameter
monitoring
as
follows:
(
1)
For
a
diffusion
flame
turbine
without
add­
on
selective
catalytic
reduction
controls
(
SCR),
the
owner
or
operator
shall
define
at
least
four
parameters
indicative
of
the
unit's
NOX
formation
characteristics
and
shall
monitor
these
parameters
continuously.
(
2)
For
any
lean
premix
stationary
combustion
turbine,
the
owner
or
operator
shall
continuously
monitor
the
appropriate
parameters
to
determine
whether
the
unit
is
operating
in
the
lean
premixed
(
low­
NOX)
combustion
mode.
The
parameters
described
in
§
75.19(
c)(
1)(
iv)(
H)(
2)
of
this
chapter
are
acceptable
for
this
purpose.
(
3)
For
any
turbine
that
uses
SCR
to
reduce
NOX
emissions,
the
owner
or
operator
shall
continuously
monitor
appropriate
parameters
to
verify
the
proper
operation
of
the
emission
controls.
(
g)
The
steam
or
water
to
fuel
ratio
or
other
parameters
that
are
continuously
monitored
as
described
in
paragraphs
(
a),
(
d)
or
(
f)
of
this
section
shall
be
monitored
during
the
performance
test
required
under
§
60.8,
to
establish
acceptable
values
and
ranges.
The
owner
or
operator
shall
develop
and
keep
on­
site
a
parameter
monitoring
plan
which
explains
the
procedures
used
to
document
proper
operation
of
the
NOX
emission
controls.
The
plan
shall
include
the
parameter(
s)
monitored
and
the
acceptable
range(
s)
of
the
parameter(
s)
as
well
as
the
basis
for
designating
the
parameter(
s)
and
acceptable
range(
s).
(
h)
The
owner
or
operator
of
any
stationary
gas
turbine
subject
to
the
provisions
of
this
subpart:
(
1)
Shall
monitor
the
total
sulfur
content
of
the
fuel
being
fired
in
the
turbine,
except
as
provided
in
paragraph
(
h)(
3)
of
this
section.
The
sulfur
content
of
the
fuel
must
be
determined
using
total
sulfur
methods
described
in
§
60.335(
b)(
10).
Alternatively,
if
the
total
sulfur
content
of
the
gaseous
fuel
during
the
most
recent
performance
test
was
less
than
0.4
weight
percent
(
4000
ppmw),
ASTM
D4084
 
82,
94,
D5504
 
01,
D6228
 
98,
or
Gas
Processors
Association
Standard
2377
 
86
(
all
of
which
are
incorporated
by
reference­
see
§
60.17),
which
measure
the
major
sulfur
compounds
may
be
used;
and
(
2)
Shall
monitor
the
nitrogen
content
of
the
fuel
combusted
in
the
turbine,
if
the
owner
or
operator
claims
an
allowance
for
fuel
bound
nitrogen
(
i.
e.,
if
an
F­
value
greater
than
zero
is
being
or
will
be
used
by
the
owner
or
operator
to
calculate
STD
in
§
60.332).
The
nitrogen
content
of
the
fuel
shall
be
determined
using
methods
described
in
§
60.335(
b)(
9)
or
an
approved
alternative.
(
3)
Notwithstanding
the
provisions
of
paragraph
(
h)(
1)
of
this
section,
the
owner
or
operator
may
elect
not
to
monitor
the
total
sulfur
content
of
the
gaseous
fuel
combusted
in
the
turbine,
if
the
gaseous
fuel
is
demonstrated
to
meet
the
definition
of
natural
gas
in
§
60.331(
v),
regardless
of
whether
an
existing
custom
schedule
approved
by
the
administrator
for
subpart
GG
requires
such
monitoring.
The
owner
or
operator
shall
use
one
of
the
following
sources
of
information
to
make
the
required
demonstration:
(
i)
The
gas
quality
characteristics
in
a
current,
valid
purchase
contract,
tariff
sheet
or
transportation
contract
for
the
gaseous
fuel,
specifying
that
the
maximum
total
sulfur
content
of
the
fuel
is
20.0
grains/
100
scf
or
less;
or
(
ii)
Representative
fuel
sampling
data
which
show
that
the
sulfur
content
of
the
gaseous
fuel
does
not
exceed
20
grains/
100
scf.
At
a
minimum,
the
amount
of
fuel
sampling
data
specified
in
section
2.3.1.4
or
2.3.2.4
of
appendix
D
to
part
75
of
this
chapter
is
required.
(
4)
For
any
new
turbine
that
commenced
construction,
reconstruction
or
modification
after
October
3,
1977,
but
before
May
29,
2003,
and
for
which
a
custom
fuel
monitoring
schedule
has
previously
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71
/
Monday,
April
14,
2003
/
Rules
and
Regulations
been
approved,
the
owner
or
operator
may,
without
submitting
a
special
petition
to
the
Administrator,
continue
monitoring
on
this
schedule.
(
i)
The
frequency
of
determining
the
sulfur
and
nitrogen
content
of
the
fuel
shall
be
as
follows:
(
1)
Fuel
oil.
For
fuel
oil,
use
one
of
the
total
sulfur
sampling
options
and
the
associated
sampling
frequency
described
in
sections
2.2.3,
2.2.4.1,
2.2.4.2,
and
2.2.4.3
of
appendix
D
to
part
75
of
this
chapter
(
i.
e.,
flow
proportional
sampling,
daily
sampling,
sampling
from
the
unit's
storage
tank
after
each
addition
of
fuel
to
the
tank,
or
sampling
each
delivery
prior
to
combining
it
with
fuel
oil
already
in
the
intended
storage
tank).
If
an
emission
allowance
is
being
claimed
for
fuelbound
nitrogen,
the
nitrogen
content
of
the
oil
shall
be
determined
and
recorded
once
per
unit
operating
day.
(
2)
Gaseous
fuel.
Any
applicable
nitrogen
content
value
of
the
gaseous
fuel
shall
be
determined
and
recorded
once
per
unit
operating
day.
For
owners
and
operators
that
elect
not
to
demonstrate
sulfur
content
using
options
in
paragraph
(
h)(
3)
of
this
section,
and
for
which
the
fuel
is
supplied
without
intermediate
bulk
storage,
the
sulfur
content
value
of
the
gaseous
fuel
shall
be
determined
and
recorded
once
per
unit
operating
day.
(
3)
Custom
schedules.
Notwithstanding
the
requirements
of
paragraph
(
i)(
2)
of
this
section,
operators
or
fuel
vendors
may
develop
custom
schedules
for
determination
of
the
total
sulfur
content
of
gaseous
fuels,
based
on
the
design
and
operation
of
the
affected
facility
and
the
characteristics
of
the
fuel
supply.
Except
as
provided
in
paragraphs
(
i)(
3)(
i)
and
(
i)(
3)(
ii)
of
this
section,
custom
schedules
shall
be
substantiated
with
data
and
shall
be
approved
by
the
Administrator
before
they
can
be
used
to
comply
with
the
standard
in
§
60.333.
(
i)
The
two
custom
sulfur
monitoring
schedules
set
forth
in
subparagraphs
(
A)
through
(
D)
of
this
paragraph,
(
i)(
3)(
i),
and
in
paragraph
(
i)(
3)(
ii)
of
this
section
are
acceptable,
without
prior
Administrative
approval:
(
A)
The
owner
or
operator
shall
obtain
daily
total
sulfur
content
measurements
for
30
consecutive
unit
operating
days,
using
the
applicable
methods
specified
in
this
subpart.
Based
on
the
results
of
the
30
daily
samples,
the
required
frequency
for
subsequent
monitoring
of
the
fuel's
total
sulfur
content
shall
be
as
specified
in
paragraph
(
i)(
3)(
i)(
B),
(
C),
or
(
D)
of
this
section,
as
applicable.
(
B)
If
none
of
the
30
daily
measurements
of
the
fuel's
total
sulfur
content
exceeds
0.4
weight
percent
(
4000
ppmw),
subsequent
sulfur
content
monitoring
may
be
performed
at
12
month
intervals.
If
any
of
the
samples
taken
at
12­
month
intervals
has
a
total
sulfur
content
between
0.4
and
0.8
weight
percent
(
4000
and
8000
ppmw),
follow
the
procedures
in
paragraph
(
i)(
3)(
i)(
C)
of
this
section.
If
any
measurement
exceeds
0.8
weight
percent
(
8000
ppmw),
follow
the
procedures
in
paragraph
(
i)(
3)(
i)(
D)
of
this
section.
(
C)
If
at
least
one
of
the
30
daily
measurements
of
the
fuel's
total
sulfur
content
is
between
0.4
and
0.8
weight
percent
(
4000
and
8000
ppmw),
but
none
exceeds
0.8
weight
percent
(
8000
ppmw),
then:
(
1)
Collect
and
analyze
a
sample
every
30
days
for
three
months.
If
any
sulfur
content
measurement
exceeds
0.8
weight
percent
(
8000
ppmw),
follow
the
procedures
in
paragraph
(
i)(
3)(
i)(
D)
of
this
section.
Otherwise,
follow
the
procedures
in
paragraph
(
i)(
3)(
i)(
C)(
2)
of
this
section.
(
2)
Begin
monitoring
at
6­
month
intervals
for
12
months.
If
any
sulfur
content
measurement
exceeds
0.8
weight
percent
(
8000
ppmw),
follow
the
procedures
in
paragraph
(
i)(
3)(
i)(
D)
of
this
section.
Otherwise,
follow
the
procedures
in
paragraph
(
i)(
3)(
i)(
C)(
3)
of
this
section.
(
3)
Begin
monitoring
at
12­
month
intervals.
If
any
sulfur
content
measurement
exceeds
0.8
weight
percent
(
8000
ppmw),
follow
the
procedures
in
paragraph
(
i)(
3)(
i)(
D)
of
this
section.
Otherwise,
continue
to
monitor
at
this
frequency.
(
D)
If
a
sulfur
content
measurement
exceeds
0.8
weight
percent
(
8000
ppmw),
immediately
begin
daily
monitoring
according
to
paragraph
(
i)(
3)(
i)(
A)
of
this
section.
Daily
monitoring
shall
continue
until
30
consecutive
daily
samples,
each
having
a
sulfur
content
no
greater
than
0.8
weight
percent
(
8000
ppmw),
are
obtained.
At
that
point,
the
applicable
procedures
of
paragraph
(
i)(
3)(
i)(
B)
or
(
C)
of
this
section
shall
be
followed.
(
ii)
The
owner
or
operator
may
use
the
data
collected
from
the
720­
hour
sulfur
sampling
demonstration
described
in
section
2.3.6
of
appendix
D
to
part
75
of
this
chapter
to
determine
a
custom
sulfur
sampling
schedule,
as
follows:
(
A)
If
the
maximum
fuel
sulfur
content
obtained
from
the
720
hourly
samples
does
not
exceed
20
grains/
100
scf
(
i.
e.,
the
maximum
total
sulfur
content
of
natural
gas
as
defined
in
§
60.331(
v)),
no
additional
monitoring
of
the
sulfur
content
of
the
gas
is
required,
for
the
purposes
of
this
subpart.
(
B)
If
the
maximum
fuel
sulfur
content
obtained
from
any
of
the
720
hourly
samples
exceeds
20
grains/
100
scf,
but
none
of
the
sulfur
content
values
(
when
converted
to
weight
percent
sulfur)
exceeds
0.4
weight
percent
(
4000
ppmw),
then
the
minimum
required
sampling
frequency
shall
be
one
sample
at
12
month
intervals.
(
C)
If
any
sample
result
exceeds
0.4
weight
percent
sulfur
(
4000
ppmw),
but
none
exceeds
0.8
weight
percent
sulfur
(
8000
ppmw),
follow
the
provisions
of
paragraph
(
i)(
3)(
i)(
C)
of
this
section.
(
D)
If
the
sulfur
content
of
any
of
the
720
hourly
samples
exceeds
0.8
weight
percent
(
8000
ppmw),
follow
the
provisions
of
paragraph
(
i)(
3)(
i)(
D)
of
this
section.
(
j)
For
each
affected
unit
required
to
continuously
monitor
parameters
or
emissions,
or
to
periodically
determine
the
fuel
sulfur
content
or
fuel
nitrogen
content
under
this
subpart,
the
owner
or
operator
shall
submit
reports
of
excess
emissions
(
or
deviations,
as
applicable)
and
monitor
downtime,
in
accordance
with
§
60.7(
c).
For
the
purpose
of
reports
required
under
§
60.7(
c),
periods
of
excess
emissions
(
or
deviations)
and
monitor
downtime
that
shall
be
reported
are
defined
as
follows:
(
1)
Nitrogen
oxides.
(
i)
For
turbines
using
water
or
steam
to
fuel
ratio
monitoring:
(
A)
A
deviation
shall
be
any
unit
operating
hour
for
which
the
average
steam
or
water
to
fuel
ratio,
as
measured
by
the
continuous
monitoring
system,
falls
below
the
acceptable
steam
or
water
to
fuel
ratio
needed
to
demonstrate
compliance
with
§
60.332,
as
established
during
the
performance
test
required
in
§
60.8.
Any
unit
operating
hour
in
which
no
water
or
steam
is
injected
into
the
turbine
shall
also
be
considered
a
deviation.
(
B)
A
period
of
monitor
downtime
shall
be
any
unit
operating
hour
in
which
water
or
steam
is
injected
into
the
turbine,
but
the
essential
parametric
data
needed
to
determine
the
steam
or
water
to
fuel
ratio
are
unavailable
or
invalid.
(
C)
Each
report
shall
include
the
average
steam
or
water
to
fuel
ratio,
average
fuel
consumption,
ambient
conditions
(
temperature,
pressure,
and
humidity),
gas
turbine
load,
and
(
if
applicable)
the
nitrogen
content
of
the
fuel
during
each
deviation.
(
ii)
If
the
owner
or
operator
elects
to
take
an
emission
allowance
for
fuel
bound
nitrogen,
then
deviations
and
periods
of
monitor
downtime
are
as
described
in
paragraphs
(
j)(
1)(
ii)(
A)
and
(
B)
of
this
section.
(
A)
A
deviation
shall
be
the
period
of
time
during
which
the
fuel­
bound
nitrogen
(
N)
is
greater
than
the
value
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/
Vol.
68,
No.
71
/
Monday,
April
14,
2003
/
Rules
and
Regulations
measured
during
the
performance
test
required
in
§
60.8
and
used
to
determine
the
allowance.
The
deviation
begins
on
the
date
and
hour
of
the
sample
which
shows
that
N
is
greater
than
the
performance
test
value,
and
ends
with
the
date
and
hour
of
a
subsequent
sample
which
shows
a
fuel
nitrogen
content
less
than
or
equal
to
the
performance
test
value.
(
B)
A
period
of
monitor
downtime
begins
when
a
required
sample
is
not
taken
by
its
due
date.
A
period
of
monitor
downtime
also
begins
on
the
date
and
hour
that
a
required
sample
is
taken,
if
invalid
results
are
obtained.
The
period
of
monitor
downtime
ends
on
the
date
and
hour
of
the
next
valid
sample.
(
iii)
For
turbines
using
NOX
and
O2
CEMS:
(
A)
An
hour
of
excess
emissions
shall
be
any
unit
operating
hour
in
which
the
4­
hour
rolling
average
NOX
concentration
exceeds
the
applicable
emission
limit
in
§
60.332(
a)(
1)
or
(
2).
For
the
purposes
of
this
subpart,
a
``
4­
hour
rolling
average
NOX
concentration''
is
the
arithmetic
average
of
the
quality­
assured
average
NOX
concentration
measured
by
the
CEMS
for
a
given
hour
(
corrected
to
15
percent
O2
and,
if
required
under
§
60.335(
b)(
1),
to
ISO
standard
conditions)
and
the
three
quality­
assured
unit
operating
hour
average
NOX
concentrations
immediately
preceding
that
unit
operating
hour.
(
B)
A
period
of
monitor
downtime
shall
be
any
unit
operating
hour
in
which
sufficient
data
are
not
obtained
to
validate
the
hour,
for
either
NOX
concentration
or
percent
O2
(
or
both).
(
C)
Each
report
shall
include
the
ambient
conditions
(
temperature,
pressure,
and
humidity)
at
the
time
of
the
excess
emission
period
and
(
if
the
owner
or
operator
has
claimed
an
emission
allowance
for
fuel
bound
nitrogen)
the
nitrogen
content
of
the
fuel
during
the
period
of
excess
emissions.
(
iv)
For
turbines
required
under
paragraph
(
f)
of
this
section
to
monitor
combustion
parameters
or
parameters
that
document
proper
operation
of
the
NOX
emission
controls:
(
A)
A
deviation
shall
be
a
4­
hour
rolling
unit
operating
hour
average
in
which
any
monitored
parameter
does
not
achieve
the
target
value
or
is
outside
the
acceptable
range
defined
in
the
parameter
monitoring
plan
for
the
unit.
(
B)
A
period
of
monitor
downtime
shall
be
a
unit
operating
hour
in
which
any
of
the
required
parametric
data
are
either
not
recorded
or
are
invalid.
(
2)
Sulfur
dioxide.
If
the
owner
or
operator
is
required
to
monitor
the
sulfur
content
of
the
fuel
under
paragraph
(
h)
of
this
section:
(
i)
For
samples
of
gaseous
fuel
and
for
oil
samples
obtained
using
daily
sampling,
flow
proportional
sampling,
or
sampling
from
the
unit's
storage
tank,
an
excess
emission
period
shall
begin
on
the
date
and
hour
of
any
sample
for
which
the
sulfur
content
of
the
fuel
being
fired
in
the
gas
turbine
exceeds
0.8
weight
percent.
The
excess
emission
period
ends
on
the
date
and
hour
that
a
subsequent
sample
is
taken
that
demonstrates
compliance
with
the
sulfur
limit.
(
ii)
If
the
option
to
sample
each
delivery
of
fuel
oil
has
been
selected,
the
owner
or
operator
shall
immediately
switch
to
one
of
the
other
oil
sampling
options
(
i.
e.,
daily
sampling,
flow
proportional
sampling,
or
sampling
from
the
unit's
storage
tank)
if
the
sulfur
content
of
a
delivery
exceeds
0.8
weight
percent.
The
owner
or
operator
shall
continue
to
use
one
of
the
other
sampling
options
until
all
of
the
oil
from
the
delivery
has
been
combusted,
and
shall
evaluate
excess
emissions
according
to
paragraph
(
j)(
2)(
i)
of
this
section.
When
all
of
the
fuel
from
the
delivery
has
been
burned,
the
owner
or
operator
may
resume
using
the
asdelivered
sampling
option.
(
iii)
A
period
of
monitor
downtime
begins
when
a
required
sample
is
not
taken
by
its
due
date.
A
period
of
monitor
downtime
also
begins
on
the
date
and
hour
of
a
required
sample,
if
invalid
results
are
obtained.
The
period
of
monitor
downtime
ends
on
the
date
and
hour
of
the
next
valid
sample.
*
*
*
*
*
(
5)
All
reports
required
under
§
60.7
(
c)
shall
be
postmarked
by
the
30th
day
following
the
end
of
each
calendar
quarter.


7.
Section
60.335
is
amended
by:


a.
Removing
paragraphs
(
a),
(
d)
and
(
e);


b.
Redesignating
paragraphs
(
b)
and
(
c)
as
paragraphs
(
a)
and
(
b),
respectively;


c.
Revising
the
new
paragraphs
(
a)
and
(
b);


d.
Redesignating
paragraph
(
f)
as
paragraph
(
c);
and

e.
Revising
the
new
paragraph
(
c)(
1).
The
revisions
and
additions
read
as
follows:

§
60.335
Test
methods
and
procedures.

(
a)
The
owner
or
operator
shall
conduct
the
performance
tests
required
in
§
60.8,
using
either
EPA
Method
20,
ASTM
D6522
 
00
(
incorporated
by
reference,
see
§
60.17),
or
EPA
Method
7E
and
either
EPA
Method
3
or
3A
in
appendix
A
to
this
part,
to
determine
NOX
and
diluent
concentration,
except
as
provided
in
§
60.8(
b).
If
ASTM
D6522
 
00
(
incorporated
by
reference,
see
§
60.17)
or
EPA
Methods
7E
and
3A
(
or
3)
are
used,
the
owner
or
operator
shall
perform
a
stratification
test
for
NOX
and
diluent
pursuant
to
the
procedures
specified
in
section
6.5.6.1(
a)
through
(
e)
appendix
A
to
part
75
of
this
chapter.
Once
the
stratification
sampling
is
completed,
the
owner
or
operator
shall
analyze
the
data
using
the
procedures
in
section
6.5.6.3(
a)
and
(
c)
to
determine
if
subsequent
RATA
testing
will
occur
along
a
short
(
0.4,
1.2
and
2.0
meters
from
the
stack
or
duct
wall)
or
long
(
16.7,
50.0,
and
83.3
percent
of
the
way
across
the
stack
or
duct)
reference
measurement
line.
The
short
or
long
reference
method
measurement
line,
as
determined
above,
will
serve
in
lieu
of
the
sampling
points
usually
required
by
EPA
Method
20.
In
no
case
shall
the
RATA
be
based
on
fewer
than
three
sample
points
as
specified
in
section
8.1.3.2
of
PS
2
in
appendix
B
to
this
part.
Other
acceptable
alternative
reference
methods
and
procedures
are
given
in
paragraph
(
c)
of
this
section.
(
b)
The
owner
or
operator
shall
determine
compliance
with
the
applicable
nitrogen
oxides
emission
limitation
in
§
60.332
and
shall
meet
the
performance
test
requirements
of
§
60.8
as
follows:
(
1)
For
each
run
of
the
performance
test,
the
nitrogen
oxides
emission
concentration
(
NOXO)
obtained
using
EPA
Method
20,
ASTM
D6522
 
00
(
incorporated
by
reference,
see
§
60.17),
or
EPA
Method
7E
shall
be
corrected
to
ISO
standard
conditions
using
the
following
equation.
Notwithstanding
this
requirement,
use
of
the
correction
equation
is
optional
for:
lean
premix
stationary
combustion
turbines;
units
used
in
association
with
heat
recovery
steam
generators
(
HRSG)
equipped
with
duct
burners;
and
units
equipped
with
add­
on
emission
control
devices:
NOX
=
(
NOXO)
(
Pr/
Po)
0.5
e19(
Ho
¥
0.00633)

(
288
°
K/
Ta)
1.53
where:
NOX
=
emission
concentration
of
NOX
at
15
percent
O2
and
ISO
standard
ambient
conditions,
ppm
by
volume,
dry
basis,
NOXO
=
observed
NOX
concentration,
ppm
by
volume,
dry
basis,
at
15
percent
O2,
corrected
using
either
EPA
Method
20
or
Method
3
or
3A
data,
Pr
=
reference
combustor
inlet
absolute
pressure
at
101.3
kilopascals
ambient
pressure,
mm
Hg,
Po
=
observed
combustor
inlet
absolute
pressure
at
test,
mm
Hg,
Ho
=
observed
humidity
of
ambient
air,
g
H2O/
g
air,

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Federal
Register
/
Vol.
68,
No.
71
/
Monday,
April
14,
2003
/
Rules
and
Regulations
e
=
transcendental
constant,
2.718,
and
Ta
=
ambient
temperature,
°
K.
(
2)
The
3­
run
performance
test
required
by
§
60.8
must
be
performed
within
±
5
percent
at
30,
50,
75,
and
90­
to­
100
percent
of
peak
load
or
at
four
evenly­
spaced
load
points
in
the
normal
operating
range
of
the
gas
turbine,
including
the
minimum
point
in
the
operating
range
and
90­
to­
100
percent
of
peak
load.
If
the
turbine
combusts
both
oil
and
gas
as
primary
or
backup
fuels,
separate
performance
testing
is
required
for
each
fuel.
Notwithstanding
these
requirements,
performance
testing
is
not
required
for
any
emergency
fuel
(
as
defined
in
§
60.331).
(
3)
For
a
combined
cycle
turbine
system
with
supplemental
heat
(
duct
burner),
the
owner
or
operator
may
elect
to
measure
the
turbine
NOX
emissions
after
the
duct
burner
rather
than
directly
after
the
turbine.
If
the
owner
or
operator
elects
to
use
this
alternative
sampling
location,
the
applicable
NOX
emission
limit
in
§
60.332
for
the
combustion
turbine
must
still
be
met.
(
4)
If
water
or
steam
injection
is
used
to
control
NOX
with
no
additional
postcombustion
NOX
control
and
the
owner
or
operator
chooses
to
monitor
the
steam
or
water
to
fuel
ratio
in
accordance
with
§
60.334(
a),
then
that
monitoring
system
must
be
operated
concurrently
with
each
EPA
Method
20,
ASTM
D6522
 
00
(
incorporated
by
reference,
see
§
60.17),
or
EPA
Method
7E
run
and
shall
be
used
to
determine
the
fuel
consumption
and
the
steam
or
water
to
fuel
ratio
necessary
to
comply
with
the
applicable
§
60.332
NOX
emission
limit.
(
5)
If
the
owner
operator
elects
to
claim
an
emission
allowance
for
fuel
bound
nitrogen
as
described
in
§
60.332,
then
concurrently
with
each
reference
method
run,
a
representative
sample
of
the
fuel
used
shall
be
collected
and
analyzed,
following
the
applicable
procedures
described
in
§
60.335
(
b)(
9).
These
data
shall
be
used
to
determine
the
maximum
fuel
nitrogen
content
for
which
the
established
water
(
or
steam)
to
fuel
ratio
will
be
valid.
(
6)
If
the
owner
or
operator
elects
to
install
a
CEMS,
the
performance
evaluation
of
the
CEMS
may
either
be
conducted
separately
(
as
described
in
paragraph
(
b)(
7)
of
this
section)
or
as
part
of
the
initial
performance
test
of
the
affected
unit.
(
7)
If
the
owner
or
operator
elects
to
install
and
certify
a
NOX
CEMS
under
§
60.334(
e),
then
the
initial
performance
test
required
under
§
60.8
may
be
done
in
the
following
alternative
manner:
(
i)
Perform
a
minimum
of
9
reference
method
runs,
with
a
minimum
time
per
run
of
21
minutes,
at
a
single
load
level,
between
90
and
100
percent
of
peak
load.
(
ii)
Use
the
test
data
both
to
demonstrate
compliance
with
the
applicable
NOX
emission
limit
under
§
60.332
and
to
provide
the
required
reference
method
data
for
the
RATA
of
the
CEMS
described
under
§
60.334(
b).
(
iii)
The
requirement
to
test
at
three
additional
load
levels
is
waived.
(
8)
If
the
owner
or
operator
is
required
under
§
60.334(
f)
to
monitor
combustion
parameters
or
parameters
indicative
of
proper
operation
of
NOX
emission
controls,
the
appropriate
parameters
shall
be
continuously
monitored
and
recorded
during
each
run
of
the
initial
performance
test,
to
establish
acceptable
operating
ranges,
for
purposes
of
the
parameter
monitoring
plan
for
the
affected
unit,
as
specified
in
§
60.334(
g).
(
9)
To
determine
the
fuel
bound
nitrogen
content
of
fuel
being
fired
(
if
an
emission
allowance
is
claimed
for
fuel
bound
nitrogen),
the
owner
or
operator
may
use
equipment
and
procedures
meeting
the
requirements
of:
(
i)
For
liquid
fuels,
ASTM
D2597
 
94
(
Reapproved
1999),
D6366
 
99,
D4629
 
02,
D5762
 
02
(
all
of
which
are
incorporated
by
reference,
see
§
60.17);
or
(
ii)
For
gaseous
fuels,
shall
use
analytical
methods
and
procedures
that
are
accurate
to
within
5
percent
of
the
instrument
range
and
are
approved
by
the
Administrator.
(
10)
If
the
owner
or
operator
is
required
under
§
60.334(
i)(
1)
or
(
3)
to
periodically
determine
the
sulfur
content
of
the
fuel
combusted
in
the
turbine,
a
minimum
of
three
fuel
samples
shall
be
collected
during
the
performance
test.
Analyze
the
samples
for
the
total
sulfur
content
of
the
fuel
using:
(
i)
For
liquid
fuels,
ASTM
D129
 
00,
D2622
 
98,
D4294
 
02,
D1266
 
98,
D5453
 
00
or
D1552
 
01
(
all
of
which
are
incorporated
by
reference,
see
§
60.17);
or
(
ii)
For
gaseous
fuels,
ASTM
D1072
 
80,
90
(
Reapproved
1994);
D3246
 
81,
92,
96;
D4468
 
85
(
Reapproved
2000);
or
D6667
 
01
(
all
of
which
are
incorporated
by
reference,
see
§
60.17).
The
applicable
ranges
of
some
ASTM
methods
mentioned
above
are
not
adequate
to
measure
the
levels
of
sulfur
in
some
fuel
gases.
Dilution
of
samples
before
analysis
(
with
verification
of
the
dilution
ratio)
may
be
used,
subject
to
the
prior
approval
of
the
Administrator.
(
11)
The
fuel
analyses
required
under
paragraphs
(
b)(
9)
and
(
b)(
10)
of
this
section
may
be
performed
by
the
owner
or
operator,
a
service
contractor
retained
by
the
owner
or
operator,
the
fuel
vendor,
or
any
other
qualified
agency.
(
c)
*
*
*
(
1)
Instead
of
using
the
equation
in
paragraph
(
b)(
1)
of
this
section,
manufacturers
may
develop
ambient
condition
correction
factors
to
adjust
the
nitrogen
oxides
emission
level
measured
by
the
performance
test
as
provided
in
§
60.8
to
ISO
standard
day
conditions.
(
2)
[
Reserved]

[
FR
Doc.
03
 
8150
Filed
4
 
11
 
03;
8:
45
am]

BILLING
CODE
6560
 
50
 
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